FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________to _________
Exact Name of
Commission Registrant State or other IRS Employer
File as specified Jurisdiction of Identification
Number in its charter Incorporation Number
- ---------------------------------------------------------------
1-12609 PG&E Corporation California 94-3234914
1-2348 Pacific Gas and California 94-0742640
Electric Company
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California 94177 San Francisco, California 94105
- -------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Pacific Gas and Electric Company PG&E Corporation
(415) 973-7000 (415) 267-7000
- -------------------------------------------------------------------
Registrant's telephone number, including area code
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding twelve months (or for such shorter period that the
registrant was required to file such reports), and (2) have been subject to such
filing requirements for the past 90 days.
Yes X No
---------- ----------
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of latest practicable date.
Common Stock Outstanding April 30, 2001:
PG&E Corporation 387,135,242 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
Form 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2001
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION PAGE
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS 3
CONDENSED CONSOLIDATED BALANCE SHEETS 4
STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS 6
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS 7
CONDENSED CONSOLIDATED BALANCE SHEETS 8
STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS 10
NOTE 1: GENERAL 11
NOTE 2: THE CALIFORNIA ENERGY CRISIS 15
NOTE 3: LONG-TERM DEBT 27
NOTE 4: BANKRUPTCY FILING 29
NOTE 5: RINGFENCING 30
NOTE 6: PRICE RISK MANAGEMENT 31
NOTE 7: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED DEBENTURES 32
NOTE 8: COMMITMENTS & CONTINGENCIES 33
NOTE 9: SEGMENT INFORMATION 39
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS 42
LIQUIDITY AND FINANCIAL RESOURCES 44
STATEMENTS OF CASH FLOWS 49
RESULTS OF OPERATIONS 52
REGULATORY MATTERS 58
ENVIRONMENTAL MATTERS 61
PRICE RISK MANAGEMENT ACTIVITIES 64
LEGAL MATTERS 67
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES 68
ABOUT MARKET RISK
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS 69
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS 73
ITEM 3. DEFAULTS UPON SENIOR SECURITIES 74
ITEM 5. OTHER INFORMATION 75
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 75
SIGNATURE 78
2
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
PG&E CORPORATION
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(in millions, except per share amounts)
For the three months
ended March 31,
---------------------
2001 2000
--------- --------
Operating Revenues
Utility $ 2,562 $2,218
Energy commodities and services 4,113 2,790
------- ------
Total operating revenues 6,675 5,008
Operating Expenses
Cost of energy for utility 3,343 796
Cost of energy commodities and services 3,839 2,472
Operating and maintenance 730 717
Depreciation, amortization, and decommissioning 103 347
------- ------
Total operating expenses 8,015 4,332
------- ------
Operating Income (Loss) (1,340) 676
Interest income 35 24
Interest expense (247) (183)
Other income (expense), net (9) (9)
------- ------
Income (Loss) Before Income Taxes (1,561) 508
Income tax provision (benefit) (610) 228
------- ------
Net Income (Loss) $ (951) $ 280
======= ======
Weighted average common shares outstanding 363 361
Earnings (Loss) Per Common Share, Basic
Net Earnings (Loss) $ (2.62) $ .78
======= ======
Earnings (Loss) Per Common Share, Diluted
Net Earnings (Loss) $ (2.62) $ .77
======= ======
Dividends Declared Per Common Share $ - $ .30
======= ======
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
--------------------------
March 31, December 31,
2001 2000
----------- ------------
ASSETS
Current Assets
Cash and cash equivalents $ 650 $ 899
Short-term investments 2,911 1,634
Accounts receivable:
Customers (net of allowance for doubtful accounts
of $91 million and $71 million, respectively) 3,007 4,342
Regulatory balancing accounts 34 222
Price risk management assets 3,457 2,039
Inventories 370 392
Income taxes receivable - 1,241
Prepaid expenses and other 902 406
-------- --------
Total current assets 11,331 11,175
Property, Plant, and Equipment
Utility 24,030 23,872
Non-utility:
Electric generation 2,075 2,008
Gas transmission 1,555 1,542
Construction work in progress 1,034 900
Other 117 147
-------- --------
Total property, plant, and equipment (at original cost) 28,811 28,469
Accumulated depreciation and decommissioning (12,073) (11,878)
-------- --------
Net property, plant, and equipment 16,738 16,591
Other Noncurrent Assets
Regulatory assets 1,821 1,773
Nuclear decommissioning funds 1,328 1,328
Price risk management assets 1,101 2,026
Other 2,668 2,398
-------- --------
Total noncurrent assets 6,918 7,525
-------- --------
TOTAL ASSETS $ 34,987 $ 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
----------------------
March 31, December 31,
2001 2000
-------- -----------
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 3,586 $ 4,530
Long-term debt, classified as current 2,309 2,391
Current portion of rate reduction bonds 290 290
Accounts payable:
Trade creditors 6,240 5,856
Regulatory balancing accounts 579 196
Other 571 459
Price risk management 3,533 1,999
Other 1,733 1,563
------- ------
Total current liabilities 18,841 17,284
Noncurrent Liabilities
Long-term debt 5,593 4,736
Rate reduction bonds 1,665 1,740
Deferred income taxes 951 1,656
Deferred tax credits 182 192
Price risk management 1,354 1,867
Other 3,715 3,864
------- ------
Total noncurrent liabilities 13,460 14,055
Preferred stock of subsidiaries 480 480
Utility obligated mandatorily redeemable preferred securities
of trust holding soley utility subordinated debentures 300 300
Common stockholders' equity
Common stock, no par value, authorized
800,000,000 shares, issued 387,183,478
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 (3,056) (2,105)
Accumulated other comprehensive loss (319) (4)
------- -------
Total common stockholders' equity 1,906 3,172
Commitments and Contingencies (Notes 1, 2 and 5) - -
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $34,987 $35,291
======= =======
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
5
PG&E CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS
(in millions)
For the three months
ended March 31,
--------------------
2001 2000
-------- --------
Cash Flows From Operating Activities
Net income (loss) $ (951) $ 280
Adjustments to reconcile net income (loss)
to net cash provided (used) by operating activities:
Depreciation, amortization, and decommissioning 103 347
Deferred income taxes and tax credits-net (527) (145)
Price risk management assets and liabilities, net 25 (11)
Other deferred charges and noncurrent liabilities (149) (9)
Net effect of changes in operating assets and liabilities:
Short-term investments (1,277) 142
Accounts receivable-trade 1,335 12
Inventories 22 55
Accounts payable 496 (89)
Regulatory balancing accounts 571 254
Accrued taxes 1,241 318
Other working capital (217) (118)
Other-net 10 26
-------- --------
Net cash provided by operating activities 682 1,062
Cash Flows From Investing Activities
Capital expenditures (352) (321)
Other-net (147) 81
-------- --------
Net cash used by investing activities (499) (240)
Cash Flows From Financing Activities
Net repayments under credit facilities (993) (547)
Long-term debt issued 906 -
Long-term debt matured, redeemed, or repurchased (236) (201)
Common stock issued - 10
Dividends paid (109) (108)
Other-net - 3
-------- --------
Net cash used by financing activities (432) (843)
-------- --------
Net Change in Cash and Cash Equivalents (249) (21)
Cash and Cash Equivalents at January 1 899 281
-------- --------
Cash and Cash Equivalents at March 31 $ 650 $ 260
======== ========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 218 $ 117
Income taxes paid (refunded) - net (1,241) 3
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
6
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(in millions)
For the three months
ended March 31,
--------------------
2001 2000
--------- --------
Operating Revenues
Electric $ 1,259 $ 1,601
Gas 1,303 617
--------- --------
Total operating revenues 2,562 2,218
Operating Expenses
Cost of electric energy 2,427 513
Cost of gas 916 283
Operating and maintenance 574 551
Depreciation, amortization, and decommissioning 65 301
--------- --------
Total operating expenses 3,982 1,648
--------- --------
Operating Income (Loss) (1,420) 570
Interest income 7 6
Interest expense 201 141
Other income (expense), net (4) (1)
--------- --------
Income (Loss) Before Income Taxes (1,618) 434
Income tax provision (benefit) (624) 200
--------- --------
Net Income (Loss) (994) 234
Preferred dividend requirement 6 6
--------- --------
Income (Loss) Available for (Allocated to) Common Stock $ (1,000) $ 228
========= ========
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
7
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
----------------------------
March 31, December 31,
2001 2000
---------- ------------
ASSETS
Current Assets
Cash and cash equivalents $ 154 $ 111
Short-term investments 2,610 1,283
Accounts receivable
Customers (net of allowance for doubtful accounts of
$53 million and $52 million, respectively) 1,574 1,711
Related parties 5 6
Regulatory balancing account 34 222
Inventories
Gas stored underground and fuel oil 151 146
Materials and supplies 133 134
Income taxes receivable - 1,120
Prepaid expenses and other 443 45
-------- -------
Total current assets 5,104 4,778
Property, Plant, and Equipment
Electric 16,446 16,335
Gas 7,584 7,537
Construction work in progress 300 249
-------- --------
Total property, plant, and equipment (at original cost) 24,330 24,121
Accumulated depreciation and decommissioning (11,281) (11,120)
-------- --------
Net property, plant, and equipment 13,049 13,001
Other noncurrent assets
Regulatory assets 1,780 1,716
Nuclear decommissioning funds 1,328 1,328
Other 1,194 1,165
-------- --------
Total noncurrent assets 4,302 4,209
-------- --------
TOTAL ASSETS $ 22,455 $ 21,988
======== ========
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
8
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
---------------------------
March 31, December 31,
2001 2000
-------- ------------
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 3,051 $ 3,079
Long-term debt, classified as current 2,293 2,374
Current portion of rate reduction bonds 290 290
Accounts payable:
Trade creditors 5,226 3,688
Related parties 177 138
Regulatory balancing accounts 579 196
Other 365 363
Price risk management 73 -
Deferred income taxes - 172
Other 719 670
------- -------
Total current liabilities 12,773 10,970
Noncurrent Liabilities
Long-term debt 3,313 3,342
Rate reduction bonds 1,665 1,740
Deferred income taxes 921 929
Deferred tax credits 182 192
Price risk management 12 -
Other 2,796 2,968
------- -------
Total noncurrent liabilities 8,889 9,171
Preferred Stock With Mandatory Redemption Provisions
6.30% and 6.57%, outstanding 5,500,000
shares, due 2002-2009 137 137
Company Obligated Mandatorily Redeemable
Preferred Securities of Trust Holding Solely
Utility Subordinated Debentures
7.90%, 12,000,000 shares due 2025 300 300
Stockholders' Equity
Preferred stock without mandatory redemption provisions
Nonredeemable-5% to 6%, outstanding
5,784,825 shares 145 145
Redeemable-4.36% to 7.04%, outstanding
5,973,456 shares 149 149
Common stock, $5 par value, authorized
800,000,000 shares, issued 321,314,760 shares 1,606 1,606
Common stock held by subsidiary, at cost,
19,481,213 shares (475) (475)
Additional paid-in capital 1,964 1,964
Accumulated deficit (2,979) (1,979)
Accumulated other comprehensive loss (54) -
------- -------
Total stockholders' equity 356 1,410
Commitments and Contingencies (Notes 1, 2, and 5) - -
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $22,455 $21,988
======= =======
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
9
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(in millions)
For the three months
ended March 31,
--------------------
2001 2000
------ ------
Cash Flows From Operating Activities
Net income (loss) $ (994) $ 234
Adjustments to reconcile net income to
net cash (used) provided by operating activities:
Depreciation, amortization, and decommissioning 65 301
Deferred income taxes and tax credit-net (170) (48)
Price risk management assets and liabilities, net 10 -
Other deferred charges and noncurrent liabilities (110) (52)
Net effect of changes in operating assets and liabilities:
Short-term investments (1,327) (2)
Accounts receivable 138 84
Income tax receivable 1,120 -
Inventories (4) 45
Accounts payable 1,579 (302)
Regulatory balancing accounts 571 254
Other working capital (352) 204
Other-net (6) (30)
------- -----
Net cash provided by operating activities 520 688
Cash Flows From Investing Activities
Capital expenditures (284) (265)
Other-net 22 54
------- -----
Net cash used by investing activities (262) (211)
Cash Flows From Financing Activities
Net repayment under credit facilities (28) (240)
Long-term debt matured, redeemed, or repurchased (187) (102)
Dividends paid - (122)
Other-net - (6)
------- -----
Net cash used by financing activities (215) (470)
------- -----
Net Change in Cash and Cash Equivalents 43 7
Cash and Cash Equivalents at January 1 111 80
------- -----
Cash and Cash Equivalents at March 31 $ 154 $ 87
======= =====
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 109 $ 75
Income taxes paid (refunded) - net (1,120) -
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
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 (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 4, on April 6, 2001, the Utility filed a voluntary
petition for relief under 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.
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.
The Utility's financial position and results of operations are the principal
factors affecting PG&E Corporation's consolidated financial position and results
of operations. 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
11
liabilities and the disclosure of contingencies. Actual results could differ
from these estimates.
Accounting for Price Risk Management Activities
PG&E Corporation, primarily through its subsidiaries, engages in price risk
management activities for both trading and non-trading purposes, as described
below.
Trading Activities
- ------------------
PG&E Corporation conducts trading activities principally through its
subsidiaries owned by PG&E National Energy Group (PG&E NEG). Trading activities
are conducted to generate profit, create liquidity, and maintain a market
presence. Net open positions (that is, positions that are not hedged) often
exist or are established due to the assessment of, and response to changing
market conditions.
Derivative and other financial instruments associated with electricity,
natural gas, natural gas liquids, and related trading activities are accounted
for using the mark-to-market method of accounting. Under mark-to-market
accounting, PG&E Corporation's trading contracts, including both physical
contracts and financial instruments, are recorded at market value, which
approximates fair value. The market prices used to value these transactions
reflect management's best estimates considering various factors, including
market quotes, time value, and volatility factors of the underlying commitments.
The values are adjusted to reflect the potential impact of liquidating a
position in an orderly manner over a reasonable period of time under present
market conditions.
Changes in the market value of these contract portfolios, resulting primarily
from newly originated transactions and the impact of commodity price or interest
rate movements, are recognized in operating income in the period of change.
Unrealized gains and losses on these contract portfolios are recorded as assets
and liabilities, respectively, from price risk management.
Non-Trading Activities
- ----------------------
In addition to the trading activities, as discussed previously, PG&E
Corporation, principally through the Utility and PG&E NEG, engages in non-
trading activities using futures, forward contracts, options, and swaps to hedge
the impact of market fluctuations on energy commodity prices, interest rates,
and foreign currencies when there is a high degree of correlation between price
movements in the derivative and the item designated as being hedged. Non-
trading activities are conducted to optimize and secure the return on risk
capital deployed within PG&E NEG's existing asset and contractual portfolio. In
addition, non-trading activity exists within the Utility to hedge against price
fluctuations of electricity and natural gas.
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,
12
"Accounting for Certain Derivative Instruments and Certain Hedging Activities".
The Statement, as amended, requires PG&E Corporation and the Utility to
recognize all derivatives, as defined in the Statement, on the balance sheet at
fair value. Derivatives are included as price risk management assets or price
risk management liabilities on the balance sheet. Changes in the fair value of
derivatives that do not qualify for hedge accounting treatment, as well as the
ineffective portion of a particular hedge, are recognized in current period
earnings. Hedge effectiveness is measured based on changes in the fair value
over time between the derivative contract and the hedged item.
SFAS No. 133 recognizes three types of hedges: fair value hedges, cash flow
hedges, and foreign currency hedges. A fair value hedge is a hedge of the
exposure to changes in the fair value of a recognized asset or liability or of
an unrecognized firm commitment, that are attributable to its fixed terms. If
the derivative qualifies and is designated as a fair value hedge, the accounting
treatment dictates that the changes in the fair value of the hedging instrument
will be offset against the changes in fair value of the hedged assets,
liabilities, or firm commitments attributable to the hedged risk and reflected
in the income statement in the current period. A cash flow hedge is a hedge of
the exposure to variability in the cash flows associated with a recognized asset
or liability, or a forecasted transaction that is attributable to changes in
variable rates or prices. If the derivative qualifies and is designated as a
cash flow hedge, the accounting treatment dictates that the effective portions
of the changes in the fair value of the hedging instrument will be recognized
in other comprehensive income (loss), a separate component of stockholders'
equity during the hedge period and will subsequently be recognized in the income
statement when the hedged item affects earnings. Foreign currency hedges may
either be classified as fair value or cash flow hedges and are subject to the
same accounting guidelines as those described above, as applicable.
Only the Utility currently has derivatives designated as fair value hedges.
These consist of swaps used to hedge commodity price risk related to purchases
of natural gas. Both PG&E Corporation and the Utility currently have
derivatives designated as cash flow hedges. For PG&E Corporation these consist
of interest rate swaps associated with variable rate debt payments used to
hedge interest rate risk. Additionally, PG&E Corporation has entered into
forward, future, and financial swap contracts for natural gas, fuel oil, and
electricity in order to hedge the commodity price risk associated with the
generating activities of the unregulated subsidiaries. The Utility's cash flow
hedges consist of forwards used to hedge commodity price risk related to natural
gas transmission. PG&E Corporation has certain foreign exchange forwards used
to economically hedge foreign currency risk associated with future purchases and
sales denominated in foreign currencies, and interest rate swaps used to
economically hedge interest rate risk, both of which were not designated as
accounting hedges. These foreign exchange and interest rate derivative
instruments not designated as hedges are accounted for using the mark-to-market
method of accounting, which requires that assets and liabilities be valued
through earnings.
Hedge effectiveness is measured quarterly. Any ineffectiveness is recognized
in the income statement in the period that the ineffectiveness occurs. If a
derivative instrument that has qualified for hedge accounting is liquidated or
sold prior to maturity, the gain or loss at the time of termination remains in
other comprehensive income (loss) until the hedged
13
item impacts earnings. For derivative instruments not designated as hedges, the
gain or loss is immediately recognized in earnings in the period of its change
in value.
PG&E Corporation and the Utility have certain derivative commodity contracts
that result in the physical delivery of commodities used in the normal course of
business. At this time, these derivatives 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 Derivative Implementation
Group of the Financial Accounting Standards Board has recently defined normal
purchases and sales to exclude certain commodity contracts that were previously
exempt under the normal purchases and sales provisions of SFAS No. 133. As
such, certain derivative commodity contracts may no longer be exempt from the
requirements of SFAS No. 133. PG&E Corporation and the Utility are currently
evaluating the impact of the recent implementation guidance, which would be
accounted for on a prospective basis, and will evaluate the impact when the
final decision regarding this issue is resolved.
PG&E Corporation's transition adjustment to implement this new Statement was a
non-material charge to earnings and a charge of $243 million to other
comprehensive income (loss). The Utility's transition adjustment to implement
this new Statement was a non-material charge to earnings and an increase of $90
million to other comprehensive income (loss).
Net gains and losses for non-trading activities recognized in earnings at
March 31, 2001, were included in various places on the income statement. These
were included as part of energy commodities and services revenue, cost of energy
commodities and services, other income (expense), net, or interest income or
interest expense on PG&E Corporation's and the Utility's Condensed Statements of
Consolidated Operations for the three-month period ended March 31, 2001.
PG&E Corporation's and the Utility's derivative gains and losses included in
other comprehensive income (loss) are reflected in earnings at the time of
terminations or settlements of the derivative instruments, along with the
amortization of the transition account. Derivative gains or losses that were
reclassified from other comprehensive income (loss) to earnings were included in
various places on the income statement. These were included as part of energy
commodities and services revenue, cost of energy commodities and services, other
income (expense), net, or interest income or interest expense on PG&E
Corporation's and the Utility's Condensed Statements of Consolidated Operations
for the three-month period ended March 31, 2001.
As of March 31, 2001, the maximum length of time over which PG&E Corporation
has its hedged our 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 February 2012.
The Utility had $243 million of cash flow hedges for commodity forward
contracts, which were derecognized or discontinued during the three-month period
ended March 31, 2001.
Earnings (Loss) Per Share
14
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 (loss) 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 Ended
March 31,
2001 2001
------ ------
(in millions)
Net Income (Loss) $ (951) $280
------ ----
Weighted average common shares outstanding 363 361
Add: Outstanding options reduced by the
number of share that could be
repurchased with the proceeds from
such purchase - 1
------ ----
Shares outstanding for diluted calculation 363 362
------ ----
Earnings (Loss) per common share, basic $(2.62) $.78
Earnings (Loss) per common share, diluted $(2.62) $.77
The diluted share base for 2001 excludes incremental shares of 457 million
related to employee stock options. These shares are excluded due to the anti-
dilutive effect as a result of the net loss. PG&E Corporation reflects the
preferred dividends of subsidiaries as other expense for computation of both
basic and diluted earnings per share.
Comprehensive Income (Loss)
The objective of PG&E Corporation's and the Utility's 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.
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 (AB1890). The electric industry
restructuring established a transition period, mandated a rate freeze, and
included a plan for recovery of generation-
15
related costs that were expected to be uneconomic under a competitive market
(transition costs). The 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 Power Exchange (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 purchased 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 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 has
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 after hearings could be held, 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 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.
16
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. In February 2001, the
California Legislature passed California Assembly Bill 1X (AB 1X), which
authorized the DWR to purchase wholesale electricity on behalf of the Utility's
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 is authorized immediately, the 3 cent surcharge will
not be collected in rates until the CPUC establishes the rate design, which is
not expected to be adopted until June 2001.
In light of the magnitude of the undercollected 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 $295 million
at March 31, 2001 and believes that the funds will be adequate to maintain its
operations through and beyond 2001. In addition, PG&E Corporation believes that
PG&E Corporation, 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.
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
17
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 undercollected wholesale electricity costs as of
the end of the earlier determined transition period will be less than the August
31 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.)
Further, it is unclear how much of the ISO's power purchases have been made by
the California Department of Water Resources (DWR) on behalf of the Utility's
customers. The Utility has filed a complaint in federal 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.
It is expected that the wholesale costs will continue to be extremely high
through 2001 unless significant changes occur in the wholesale electricity
market. The generation-related costs component, which provides for recovery of
wholesale electricity purchased by the Utility and, if available, for recovery
of transition costs, was approximately 6.4 cents and 5.4 cents per kWh, during
the three months ended 2001 and 2000, respectively. As discussed below, the
CPUC approved an average 3.0 cents per kWh surcharge for power costs incurred
after March 27, 2001, but the 3-cent surcharge will not be collected in rates
until the CPUC establishes an appropriate rate design for the surcharge, which
is not expected to be adopted until June 2001.
During the quarter ended March 31, 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 Statement of
Operations. The amount of undercollected purchased power costs incurred for the
three month period ended March 31, 2001 was
18
approximately $1.9 billion. Under current CPUC decisions, if this
undercollection is not recovered through frozen rates by the end of the
transition period, it cannot be recovered. 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 undercollected 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.
Transition Cost Recovery
Beginning January 1, 1998, the Utility started amortizing eligible transition
costs, including most generation-related regulatory assets. These transition
costs were offset by or recovered through the frozen rates, market valuation of
generation assets in excess of book value, net energy sales from the Utility's
electric generation facilities, and the amount by which long-term contract
prices to purchase electricity were lower than the PX prices. Transition costs
and associated recoveries are recorded in the Utility's Transition Cost
Balancing Account (TCBA). During the transition period, a reduced rate of
return on common equity of 6.77% applies to all generation assets, including
those generation assets reclassified to regulatory assets.
During the transition period, the CPUC reviews the Utility's compliance with
accounting methods established in the CPUC's decisions governing transition
costs recovery and the amount of transition costs requested for recovery. In
January 2001, the CPUC approved all transition costs that were amortized from
July 1, 1998, to June 30, 1999. The CPUC currently is reviewing transition
costs amortized from July 1, 1999, to June 30, 2000.
Mitigation Efforts
The Utility is actively exploring ways to reduce its exposure to the higher
wholesale electricity costs and to recover its written-off undercollected
wholesale electricity costs and 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, 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
- -------------------------
19
On October 16, 2000, the Utility joined with Southern California Edison (SCE)
and The Utility Reform Network (TURN) in filing a petition with the Federal
Energy Regulatory Commission (FERC) requesting that the FERC (1) immediately
find the California wholesale electricity market to be not workably competitive
and the resulting prices to be unjust and unreasonable; (2) immediately impose a
cap on the price for energy and ancillary services; and (3) institute further
expedited proceedings regarding the market failure, mitigation of market power,
structural solutions, and responsibility for refunds.
On December 15, 2000, the FERC issued an order in response to the above
filing. The remedies proposed by the FERC include, 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 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.
On April 26, 2001, the FERC issued an order requiring all ISO-participating
generators and nonpublic utility sellers participating in the ISO markets or
using the ISO transmission system to offer their output in real-time to the ISO
(except for hydroelectric facilities). The order also requires generators to
justify prices above their marginal costs to generate. Further, when a stage 1,
2, or 3 emergency is in effect, price mitigation become effective. The real-time
electric prices will no longer clear at the single highest price or at a soft
cap of $150 per MW, but will clear at a proxy price based on the highest cost
units required to be used each day, and published fuel costs and emission credit
information. This mitigation plan will become effective on May 29, 2001. The
FERC will monitor bidding activities of generators, forward prices in the
electricity and natural gas market and plant outages. Any bids that prove to be
unjustified will be subject to refund. The FERC has requested comments on
various aspects of its order. The FERC also has indicated that it intends to
open an investigation into prices and sales into the Western United States and
consider imposing price mitigation measures similar to those proposed for
California markets. The order also requires that the ISO and the three
California investor owned utilities file a proposal regarding the establishment
of west-wide regional transmission organization (RTO) by June 1, 2001.
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 states 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
20
decisions, state regulators cannot disallow such costs. The Utility's lawsuit
also alleges 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
January 29, 2001, the Utility's lawsuit was transferred to the federal district
court in Los Angeles where SCE has its identical case pending.
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 interim orders that will only become final upon a grant or denial of
rehearing.
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, authorizes 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 (QF) contracts, existing bilateral contracts,
and ancillary services (the California Procurement Adjustment or CPA). The CPA
is payable to the DWR by each utility upon receipt from its retail end use
customers.
Initially, the DWR has 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. The ISO billed, and is expected to continue to bill the
Utility for those costs. 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. It is not
clear whether the Utility will ultimately be responsible for these costs from
February through April 6, 2001. The Utility has expensed these costs in the
accompanying condensed financial statements.
By early January 2001, the Utility failed to meet the creditworthiness
standards under the ISO's tariff for purchasing and scheduling power from third
parties. On January 5, 2001, the ISO filed a proposed tariff amendment with the
FERC to permit the Utility to continue scheduling transactions through the ISO.
The ISO implemented its proposed tariff amendment immediately. On February 14,
2001, the FERC issued an order rejecting the ISO's proposed tariff amendment,
prohibiting the Utility from scheduling power from a third party supplier,
unless the Utility was creditworthy or was backed by creditworthy parties. 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. The ISO continued to charge the Utility for the power
it buys on an emergency basis, despite the FERC ruling. 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.
21
The ISO has not indicated that it will comply with the FERC and cease billing
the Utility for its third party power purchases. The Utility has filed a
complaint against the ISO in Bankruptcy Court regarding this issue.
Rate Stabilization Plan (RSP)
- -----------------------------
On November 22, 2000, the Utility filed an application with 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 rate stabilization plan proceeding. The ruling stated that in phase
one of the case, the scope of the proceeding will 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 undercollected balances in the
Utility's 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
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.
22
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 is authorized immediately, the 3.0 cents per kWh surcharge will not
be collected in rates until the CPUC establishes an appropriate rate design for
the surcharge, which is not expected to be adopted until June 2001. 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 overcollections, or (3) to the extent any administrative body
or court denies the refunds of overcollections 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 in
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 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 cent per kWh interim
surcharge adopted by the CPUC on January 5, 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 March 27, 2001, and 9.471 cents per kWh
after March 27, 2001, reflecting the authorized 3-cent increase. 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. The amount of power supplied 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 provided 45 days earlier and the Utility's
company-wide average generation-related rate of 9.471 cents per kWh.
The CPUC also ordered that the utilities immediately pay the sums owed to the
DWR for power sold by the DWR from January 18, 2001 through January 31, 2001,
under California Senate Bill 7X. Based on an estimated number of kWh sold by
the DWR, the Utility paid approximately $30 million to the DWR at the rate of
5.471 centers per kWh as adopted by the CPUC.
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,
the CPA, 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, OFs 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 utility's generation-related revenues (for the Utility the CPUC has
proposed that
23
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 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.
To the extent the DWR does not buy enough power to cover the Utility's net
open position, the ISO purchases emergency power on the high-priced spot market
to meet system reliability requirements and the net open position. Despite the
FERC's order prohibiting the ISO from charging non-creditworthy utilities for
the ISO's third party power purchases, the ISO may continue to charge the
Utility a proportionate share of the ISO's purchases. As discussed above, the
Utility believes it is not responsible for such ISO charges. The DWR has
advised the CPUC that its revenue requirement for the DWR's power purchases is
$4.715 billion and has asked the CPUC to establish specific rates payable to the
DWR to collect that revenue requirement as authorized by AB1X. The DWR's stated
revenue requirement is greater than the revenues that would be provided by the
3-cent surcharge. Unless the CPUC increase rates to provide sufficient revenues
for the DWR to recover its revenue requirement, none of the revenues from the 3-
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).
Since the end of January 2001, the Utility has been paying only 15% of amounts
due qualifying facilities (QFs). 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 QF. 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
24
average QF energy and capacity payments from approximately 12.7 cents per kWh to
12.3 cents per kWh.
The CPUC also adopted TURN's proposal to transfer on a monthly basis the
balance in each Utility's TRA to the Utility's TCBA. The TRA is a regulatory
balancing account that is credited with total revenue collected from ratepayers
through frozen rates and which tracks undercollected 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 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 has filed an
application for rehearing of this decision. The Utility also has requested the
Bankruptcy Court to enjoin the CPUC from requiring the Utility to implement the
regulatory accounting changes. A hearing is set for May 14, 2001, to consider
the Utility's request.
Bilateral Contracts
- -------------------
Under the terms of the 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 PG&E reaching agreement with
the CPUC on reasonableness standards. After two months of unsuccessful
discussions with CPUC, on October 16, 2000, PG&E 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. As of March 31, 2001,
individual contracts range in size from approximately 92,000 MWhs to 3,504,000
MWhs of supply annually. The contracts extended to 2005. As a result of the
downgrade in PG&E's credit rating and also its subsequent bankruptcy filing,
certain of these contracts were terminated.
PX Energy Credits
- -----------------
25
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 three
months ended March 31, 2001, the PX credits reduced electric revenue by $322
million. The Utility ceased paying most of these credits in December 2000, and
as of March 31, 2001, the total of accumulated credits for direct access
customers that have not been paid by the Utility is approximately $510 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
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 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 March 31, 2001, the book
value of the Utility's net investment in hydroelectric generation assets was
approximately $688 million.
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
26
long as the Utility owned Diablo Canyon. Under the proposal, the Utility would
share the net benefits of operating Diablo Canyon based on the audited profits
from operations, determined consistent with the prior CPUC decisions. If Diablo
Canyon experiences losses, such losses would be 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. It is uncertain what future ratemaking will be
applicable to Diablo Canyon.
Cost of Electric Energy
For the three months ended March 31, 2001 and 2000, the cost of electric
energy for the Utility, reflected on the Utility's Condensed Statement of
Consolidated Operations, comprises the cost of fuel for electric generation and
QF purchases, the cost of PX purchases, and ancillary services charged by the
ISO, net of sales to the PX, as follows:
2001 2000
---- ----
(in millions)
Cost of fuel resources at market prices $2,631 $ 628
Proceeds from sales to the PX (204) (115)
------ -----
Total Utility cost of electric energy $2,427 $ 513
------ -----
Note 3: LONG-TERM DEBT
On January 16 and 17, 2001, in response to the continued energy crisis,
Standard and Poor's (S&P) and Moody's Investors Service (Moody's) respectively,
downgraded PG&E Corporation's credit ratings to below investment grade. The
downgrade, in addition to PG&E Corporation's and the Utility's non-payment of
commercial paper constituted an event of default under both the $436 million and
the $500 million credit facilities. In response, the banks immediately
terminated their outstanding commitments under these defaulted credit
facilities. Through February 28, 2001, PG&E Corporation had $501 million in
outstanding commercial paper, of which $457 million came due and was not paid.
On March 2, 2001, PG&E Corporation refinanced its debt obligations with $1
billion in aggregate proceeds of two term loans under a common credit agreement
with General Electric Capital Corporation and Lehman Commercial Paper, Inc. In
accordance with the credit agreement, the proceeds, together with other PG&E
Corporation cash, were used to pay the $501 million in outstanding commercial
paper, $434 million in borrowings under PG&E Corporation's long-term revolving
credit facility, and $116 million to PG&E Corporation's shareholders of record
on December 15, 2000 in satisfaction of the defaulted fourth quarter 2000 common
stock dividend. Further, approximately $99 million was used to pre-pay the
first year's
27
interest under the credit agreement and to pay transaction expenses associated
with the debt restructuring.
The loans will mature on March 2, 2003 (which date may be extended at the
option of PG&E Corporation for up to one year upon payment of a fee of up to 5%
of the then outstanding indebtedness), or earlier, if a spin-off of the shares
of PG&E NEG were to occur. As required by the credit agreement, PG&E
Corporation has given the lenders a security interest in PG&E NEG. The loans
prohibit PG&E Corporation from declaring dividends, making other distributions
to shareholders, or incurring additional indebtedness unless it meets certain
requirements. The loan also prohibits PG&E NEG from making distributions to
PG&E Corporation and restricts certain other intercompany transactions.
Further, as required by the credit agreement, NEG LLC has granted to
affiliates of the lenders options that entitle these affiliates to purchase up
to 3% of the shares of PG&E NEG at an exercise price of $1.00 based on the
following schedule:
Percentage of
Shares Subject
To PG&E NEG Options
-------------------
Loans outstanding for:
Less than six months 2.0%
Six to eighteen months 2.5%
Greater than eighteen months 3.0%
The option becomes exercisable on the date of full repayment or earlier, if an
initial public offering of the shares of PG&E NEG (IPO) were to occur. PG&E NEG
has the right to call the option in cash at a purchase price equal to the fair
market value of the underlying shares, which right is exercisable at any time
following the repayment of the loans. If an IPO has not occurred, the holders
of the option have the right to require NEG LLC or PG&E Corporation to
repurchase the option at a purchase price equal to the fair market value of the
underlying shares, which right is exercisable at any time after the earlier of
full repayment of the loans or 45 days before expiration of the option. The
option will expire 45 days after the maturity of the loans. PG&E Corporation
will account for the options by recording the fair value of the option at
issuance as a debt issuance cost to be amortized over the expected life of the
loans. The options will be marked through an increase or decrease to current
earnings.
Under the credit agreement, PG&E NEG is permitted to make investments, incur
indebtedness, sell assets, and operate its businesses pursuant to its business
plan. Mandatory repayment of the loans will be required from the net after-tax
proceeds received by PG&E NEG or any subsidiary of PG&E NEG from (1) the
issuance of indebtedness, (2) the issuance or sale of any equity (except for
cash proceeds from an IPO), (3) asset sales, and (4) casualty issuance,
condemnation awards, or other recoveries. However, if such proceeds are
retained as cash, used to pay indebtedness, or reinvested in PG&E NEG's
businesses, mandatory repayment will not be required.
Any net proceeds from an IPO must be used to reduce the outstanding balance of
the loans to $500 million or less. In addition, all distributions made by PG&E
NEG to PG&E Corporation other than (1) to reimburse PG&E Corporation for
corporate overhead expenses, (2) pursuant to
28
any tax sharing arrangements which PG&E NEG and PG&E Corporation are parties,
and (3) pursuant to any note that may be repayable to PG&E Corporation in
connection with an IPO and similar arrangements must be used to pay the loans.
The credit agreement also prohibits PG&E Corporation from taking certain
actions, including a restriction against declaring or paying any dividends for
as long as the loans are outstanding. A breach of covenants, including
requirements that (1) PG&E NEG's unsecured long-term debt have a credit rating
of at least BBB- by S&P or Baa3 by Moody's, (2) the ratio of fair market value
of PG&E NEG to the aggregate amount of principal then outstanding under the
loans is not less than 2 to 1, and (3) PG&E Corporation maintain a cash or cash
equivalent reserve of at least 15% of the total principal amount of the loans
outstanding, entitles the lenders to declare the loans to be due and payable.
Note 4: BANKRUPTCY FILING
The Utility had been drawing on its $1 billion facility to pay maturing
commercial paper. As of January 16, 2001, the Utility had drawn down $938
million under this facility. On January 16 and 17, 2001, S&P and Moody's
respectively, downgraded the Utility's credit ratings to below investment grade.
This downgrade resulted in an event of default under the $850 million credit
facility, while the Utility's non-payment of commercial paper exceeding $100
million constituted events of default under both the $1 billion and $850 million
credit facilities.
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 15, 2001, to PG&E Corporation and PG&E
Holdings, Inc., a subsidiary of the Utility. In addition, the Utility's Board
of Directors decided not to declare the regular preferred stock dividends of
$6.3 million for the three-month period ending 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.
The Utility has also deferred quarterly interest payments of $6.1 million 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 of $5.9 million on the 7.90% Cumulative Quarterly Income
Preferred Securities, Series A (QUIPS) issued by PG&E Capital I, due on April 2,
2001, have been similarly deferred. Distributions can be deferred up to a
period of five years per the indenture. Under the indenture, investors
accumulate interest on the unpaid distributions at the rate of 7.90%.
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. On January 25, 2001, a California Superior Court
judge granted the Utility's
29
application for a temporary restraining order, which thereby restrained and
enjoined the PX and its agents from liquidating the Utility's contracts in the
block forward market, pending hearing on a preliminary injunction on February 5,
2001. Immediately before the hearing on the preliminary injunction, California
Governor Gray Davis, acting under California's Emergency Services Act,
commandeered the contracts for the benefit of the state. Under the Act, the DWR
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.
As a result of (1) the failure by the DWR to assume the full procurement
responsibility for the Utility's net open position as was provided under AB1X,
(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 uncollected 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. 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. Subject to the approval of the bankruptcy court, the Utility's intent is
to pay its ongoing costs of doing business while seeking resolution of the
wholesale power crisis. It is the Utility's intention to continue to pay
employees, vendors, suppliers, and other creditors to maintain essential
distribution and transmission services. However, the Utility is not in a
position to pay maturing or accelerated obligations, nor is the Utility in a
position to pay the ISO, PX, and the QFs, the massive amounts due for the
Utility's power purchases above the amount included in rates for power purchase
costs. The Utility's current actions are intended to allow the Utility to
continue to operate while the bankruptcy proceedings continue.
Note 5: RINGFENCING
In December 2000 and during the first quarter of 2001, PG&E Corporation and
PG&E NEG undertook a corporate restructuring of PG&E NEG, known as a
"ringfencing" transaction. The ringfencing complied with credit rating agency
criteria designed to further separate a subsidiary from its parent and
affiliates, enabling PG&E NEG, PG&E Gas Transmission, Northwest Corporation
(PG&E GTN), and PG&E Energy Trading Holdings Corp. to receive or retain their
own credit rating, based upon their creditworthiness. The ringfencing involved
the creation of new special purpose entities (SPEs) as intermediate owners
between PG&E Corporation and its non CPUC-regulated subsidiaries. These new SPEs
are: NEG LLC, which owns 100% of the stock of PG&E NEG; GTN Holdings LLC, which
owns 100% of the stock of PG&E GTN; and PG&E Energy Trading Holdings LLC which
owns 100% of the stock of PG&E Corporation's energy trading subsidiaries, PG&E
Energy Trading-Power, L.P. and PG&E Energy Trading-Gas Corporation, and their
affiliates (PG&E ET). In addition, PG&E NEG's organizational documents were
modified to include the same structural elements as the SPEs to meet credit
rating agency criteria. Ringfencing was undertaken to enable PG&E NEG and
various of its affiliates to obtain
30
or maintain investment grade ratings. The SPEs require unanimous approval of
their respective boards of directors, which includes an independent director,
before they can (a) consolidate or merge with any entity, (b) transfer
substantially all of their assets to any entity, or (c) institute or consent to
bankruptcy, insolvency, or similar proceedings or actions. The SPEs may not
declare or pay dividends unless the respective boards of directors have
unanimously approved such action and the company meets specified financial
requirements.
NOTE 6: PRICE RISK MANAGEMENT
Trading and Non-Trading Activities
PG&E Corporation's net gain (loss) on trading contracts for the three-month
period ended March 31, are as follows:
2001 2000
----- -----
(in millions)
Swaps $(349) $(23)
Options (7) 62
Futures 32 37
Forward contracts 352 (31)
----- -----
Net gain $ 28 $ 45
===== =====
Below is a table summarizing the quantitative information associated with PG&E
Corporation's cash flow hedges for the three-month period ended March 31, 2001.
Only the Utility currently uses fair value hedges. The Utility's fair value
hedge is subject to a regulatory mechanism, and as such, it is deferred for
future recovery or refund and included on the balance sheet with no immediate
earnings impact. The Utility's price risk management strategies consist of the
use of non-trading (hedging) financial instruments, designated as both cash
flow hedges and fair value hedges. Gains and losses associated with the use of
some of the Utility's financial instruments primarily affect regulatory
accounts, depending on the business unit and the specific program involved.
While the use of the Utility's financial 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.
PG&E Corporation
----------------
(in millions)
Amount of the hedge's ineffectiveness $ (2)
----
Net loss recognized in earnings $ (2)
----
PG&E Corporation and the Utility's estimated net derivative gains or losses
included in other comprehensive loss at March 31, 2001 that will be reclassified
into earnings within the next twelve months are a net derivative loss of $146
million for PG&E Corporation and a net derivative loss of $25 million for the
Utility.
31
The schedule below summarizes the activities affecting accumulated other
comprehensive income (loss) from derivative instruments for the three-month
period ended March 31, 2001.
PG&E Corporation Utility
----------------- -------
(in millions)
Beginning accumulated derivative gain (loss)
from SFAS No. 133 transition adjustments at
January 1, 2001 $(243) $ 90
Net change of current period hedging transactions
gain (loss) (29) 1
Net reclassification to earnings (43) (143)
----- -----
Ending accumulated derivative gain (loss) (315) (52)
Foreign currency translation adjustment (4) (2)
----- -----
Ending accumulated other comprehensive loss $(319) $ (54)
===== =====
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 $25 million due to the
nonperformance of counterparties during the three-month period ended March 31,
2001. Counterparties considered to be investment grade or higher comprise 87%
of the total credit exposure. At March 31, 2001, PG&E Corporation's and the
Utility's gross credit risk amounted to $2.1 billion and $758 million,
respectively.
NOTE 7: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES
The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust), has
outstanding 12 million shares of 7.90% QUIPS, with an aggregate liquidation
value of $300 million. Concurrent with the issuance of the QUIPS, the Trust
issued to the Utility 371,135 shares of common securities with an aggregate
liquidation value of $9 million. The Trust in turn used the net proceeds from
the QUIPS offering and issuance of the common stock securities to purchase
subordinated debentures issued by the Utility with a face value of $309 million,
due 2025. These subordinated debentures are the only assets of the Trust.
Proceeds from the sale of the
32
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 PG&E Capital I 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 United States 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 8: COMMITMENTS AND CONTINGENCIES
Nuclear Insurance
The Utility has insurance coverage for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited (NEIL).
Under this insurance, if a nuclear generating facility suffers a loss due to a
prolonged accidental outage, the Utility may be subject to maximum retrospective
assessments of $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
33
of $200 million, then the Utility may be assessed up to $176 million per
incident, with payments in each year limited to a maximum of $20 million per
incident.
Environmental Remediation
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 in 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 the lower end of this range.
At March 31, 2001, the Utility expects to spend $307 million for hazardous
waste remediation costs at identified sites, including divested fossil-fueled
power plants. The cost of the hazardous substance remediation ultimately
undertaken by the Utility is difficult to estimate. A change in estimate may
occur in the near term due to uncertainty concerning the Utility's
responsibility, the complexity of environmental laws and regulations, and the
selection of compliance alternatives. If other potentially responsible parties
are not financially able to contribute to these costs or further investigation
indicates that the extent of contamination or necessary remediation is greater
than anticipated, the Utility could spend as much as $460 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 $307 million and
$320 million at March 31, 2001 and December 31, 2000, respectively. The $307
million accrued at March 31, 2001 includes (1) $139 million related to the pre-
closing remediation liability, associated with the divested generation
facilities discussed further in the "Generation Divestiture" section of Note 2,
and (2) $168 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 $307 million environmental remediation
liability, the Utility has
34
recovered $193 million through rates, and expects to recover another $84 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.
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
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
- --------------------------
35
The U.S. Environmental Protection Agency (EPA) and the U.S. Department of
Justice have 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, EPA visited both facilities. PG&E NEG believes this request for
information is part of EPA's industry-wide investigation of coal-fired plants'
compliance with the Clean Air Act requirements governing plant modifications.
PGE&NEG also believes that any changes made to the plants were routine
maintenance or repairs and, therefore, did not require permits. EPA has not
issued a notice of violation or filed any enforcement action against PG&E NEG at
this time. Nevertheless, if EPA disagrees with PG&E NEG's conclusion with
respect to the changes 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.
In addition to the EPA, states may impose more stringent air emissions
requirements. On May 11, 2001, the Massachusetts Department of Environmental
Protection issued regulations imposing new restrictions of certain air emissions
from existing coal-fired power plants. These requirements will primarily impact
PG&E NEG's Salem Harbor and Brayton Point generating facilities. Through 2008,
it may be necessary to spend approximately $265 million to comply with these
regulations. In addition, with respect to approximately 600 megawatts (MW) (or
about 12%) of PG&E NEG's New England capacity, it may be necessary to implement
fuel conversion, limit operations, or install additional environmental controls.
PG&E Gen's existing power plants, including USGenNE facilities, are subject to
federal and state water quality standards with respect to discharge constituents
and thermal effluents. Three of the fossil-fueled plants owned and operated by
USGenNE are operating pursuant to NPDES permits that have expired. For the
facilities whose NPDES permit have expired, permit renewal applications are
pending, and it is anticipated that all three facilities will be able to
continue to operate in substantial compliance with their prior permits until
new permits are issued. It is estimated that USGenNE's cost to comply with the
new permit conditions could be as much as $60 million through 2005. It is
possible that the new permits may contain more stringent limitations than prior
permits.
During September 2000, USGenNE signed a series of agreements that require,
among other things, USGenNE to alter its existing waste water treatment at two
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 expected cost of these improvements, which are
underway,is $21 million.
PG&E NEG anticipates spending up to approximately $330 million, net of
insurance proceeds, through 2008, for environmental compliance at currently
operating facilities, which primarily addresses: (a) new Massachusetts air
regulations made public on April 23, 2001 affecting Brayton Point and Salem
Harbor Stations; (b) wastewater permitting requirements that may apply to
Brayton Point, Salem Harbor and Manchester Street Stations; and (c)
requirements that are
36
reflected in a consent decree concerning wastewater treatment facilities at
Salem Harbor and Brayton Point stations.
LEGAL MATTERS
Utility
The Utility's Chapter 11 bankruptcy on April 6, 2001, discussed in Note 4
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 Pacific Gas and
Electric Company 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 Assembly Bill 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
37
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
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
- --------------------------
On April 16, 2001, a complaint was filed against PG&E Corporation and the
Utility in the U.S. District Court for the Central District of California.
The complaint alleges that PG&E Corporation and the Utility violated federal
securities laws, generally acceptable 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.
38
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 operation.
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.
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, March 31, 2001 $184
----
NOTE 9: SEGMENT INFORMATION
PG&E Corporation has identified three reportable operating segments, which
were determined based on similarities in economic characteristics, products and
services, types of customers, methods of distributions, the regulatory
environment, and how information is reported to PG&E Corporation's key decision
makers. As discussed below, these segments represent a change in the reportable
segments. In accordance with generally accepted accounting standards 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
39
Corporation's 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,
Pacific Gas and Electric Company, provides natural gas and electric service to
its customers.
PG&E National Energy Group
- --------------------------
PG&E Corporation's subsidiary, the 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 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.
40
Segment information for the three months ended March 31, 2001, and 2000 was as
follows:
National Energy Group
---------------------------------------------
Integrated Interstate NEG Other &
Total Energy and Pipeline Elimini- Elimi-
(in millions) Utility NEG Marketing Operations nations nations(2) Total
------- --------- ----------- ---------- --------- ---------- -------
For the three months ended March 31, 2001
Operating revenues $ 2,560 $ 4,115 $ 4,068 $ 56 $ (9) $ - $ 6,675
Intersegment revenues(1) 2 93 84 9 - (95) -
------- --------- ----------- ---------- ------- ------ -------
Total operating revenues 2,562 4,208 4,152 65 (9) (95) 6,675
------- --------- ----------- ---------- ------- ------ -------
Net Income (loss) (1,000) 54 35 20 (1) (5) (951)
Total assets at March 31, 2001(3) $22,455 $12,174 $10,755 $1,188 $ 231 $ 358 $34,987
For the three months ended March 31, 2000(4)
Operating revenues $ 2,214 $ 2,794 $ 2,529 $ 257 $ 8 $ - $ 5,008
Intersegment revenues(1) 4 29 4 25 - (33) -
------- --------- ----------- ---------- ------- ------ -------
Total operating revenues 2,218 2,823 2,533 282 8 (33) 5,008
------- --------- ----------- ---------- ------- ------ -------
Net Income 228 52 38 14 - - 280
Total assets at March 31, 2000(3) $21,357 $ 8,083 $ 5,751 $2,332 - $ (244) $29,196
(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, PG&E Telecom, 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.
41
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
4 of the Notes to the Condensed Consolidated Financial Statements.
PG&E Corporation's subsidiary, the 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 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
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. 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,"
42
"expects," "anticipates," "plans," "believes," and other similar expressions.
Actual results could differ materially from those contemplated by the forward-
looking statements.
Although PG&E Corporation and the Utility are not able to predict all of the
factors that may affect future results, some of the factors that could cause
future results to differ materially from those expressed or implied by the
forward-looking statements, or historical results include:
. the outcome of the Utility's regulatory proceedings;
. 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 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 undercollected 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 markets 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
43
operations of these development projects are delayed or prevented because
of various development and construction risks;
. 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;
. 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 first quarter 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
undercollected purchased power costs were probable of recovery from ratepayers.
In addition, during the
44
first quarter of 2001, the Utility recognized after tax charges of $1.1 billion
representing undercollected 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 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 2,3, and 4 of the 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 18.16 cents per kilowatt-hour (kWh) for the seven-month period of June
2000 through December 2000, as compared to an average cost of 4.23 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 undercollection 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
syndication agreement. At December 31, 2000, the Utility had borrowed $614
million against its five-
45
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 CPUC approved an
interim one-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, Inc., 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 ending 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 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 to 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
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. On January 25, 2001, a California Superior Court
judge granted the Utility's application for a temporary restraining order, which
thereby restrained and enjoined the PX and its agents from liquidating the
Utility's contracts in
46
the block-forward market, pending hearing on preliminary injunction on February
5, 2001. Immediately before the hearing on the preliminary injunction,
California Governor Gray Davis, acting under California's Emergency Services
Act, commandeered the contracts 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.
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 California Department of Water Resources (DWR) to
purchase electricity for the Utility's customers. Assembly Bill 1X (AB1X) 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 significant amounts of power on the spot market at prevailing market
prices. The DWR is not purchasing electricity for the Utility's entire net open
position (the amount of power that cannot be met by the Utility's own or
contracted-for generation). To the extent that the DWR is not purchasing
electricity for the entire net open position, the remainder is being procured by
the ISO. To that extent, the ISO is charging the Utility for those purchases.
As a result of (1) the failure by the state to assume the full procurement
responsibility for the Utility's net open position, as was provided under AB1X,
(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 undercollected 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.
Subject to the approval by the Bankruptcy Court, the Utility's intent is to
pay its ongoing costs of doing business while seeking resolution of the
wholesale energy crisis. It is the Utility's intention to continue to pay
employees, vendors, suppliers, and other creditors to maintain essential
distribution and transmission services. However, the Utility is not in a
position to pay maturing or accelerated obligations, nor is the Utility in a
position to pay the ISO, PX, and the QFs the amounts due for the Utility's power
purchases above the amount included in rates for power purchase costs. The
Utility's current actions are intended to allow the Utility to continue to
operate while efforts to reach a regulatory or legislative solution continue.
The Utility's plans will be subject to approval of the Bankruptcy Court.
The Utility has also 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% Cumulative Quarterly Income Preferred Securities, Series A
(QUIPS) issued by PG&E Capital I, due on April 2, 2001, have been similarly
deferred. Distributions can be deferred
47
up to a period of five years per the indenture. Per the indenture, investors
will accumulate interest on the unpaid distributions at the rate of 7.90%.
The weakened financial condition of the Utility also has impacted its ability
to supply natural gas to its natural gas customers. In December 2000 and
January 2001, several gas suppliers demanded prepayment, cash on delivery, or
other forms of payment assurance before they would deliver gas, instead of the
normal payment terms, under which the Utility would pay for the gas after
delivery. As the Utility was unable to meet such demands at that time, several
gas suppliers refused to supply gas, accelerating the depletion of the Utility's
gas storage reserves and potentially exacerbating the electric power crisis if
the Utility were required to divert gas from industrial users, including natural
gas fired power plant operators.
The U.S. Secretary of Energy issued a temporary order on January 19, 2001,
requiring the gas suppliers to continue to make deliveries to avoid a worsening
natural gas shortage emergency. However, this order expired on February 7,
2001, and certain companies, representing about 10% of the Utility's natural gas
suppliers, terminated deliveries after the order expired.
The Utility tried to mitigate the worsening supply situation by withdrawing
more gas from storage and, when able, purchasing additional gas on the spot
market. Additionally, on January 31, 2001, the CPUC authorized the Utility to
pledge its gas account receivables and its gas inventories for up to 90 days
(extended to 180 days in a CPUC draft decision issued on February 15, 2001) to
secure gas for its core customers. At March 29, 2001, the amount of gas
accounts receivables pledged was approximately $900 million. As of March 29,
2001, approximately 30% of the Utility's suppliers of natural gas had signed
security agreements with the Utility and discussions were continuing with the
Utility's other suppliers. Additionally, the Utility is currently implementing
a program to obtain longer-term summer and winter supplies and daily spot
supplies.
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
48
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 $116 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. See Note 3 of the
Notes to the Condensed Consolidated Financial Statements for a detailed
description of the loan.
On March 15, 2001, PG&E Corporation's corporate credit rating was withdrawn by
S&P due to the March 2, 2001, refinancing of its obligations and the fact that
PG&E Corporation had no more public debt to be rated.
PG&E Corporation itself had had cash and short-term investment of $295 million
at March 31, 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.
PG&E National Energy Group
- --------------------------
In December 2000, and during the first quarter of 2001, PG&E Corporation and
PG&E NEG undertook a corporate restructuring of PG&E NEG, known as a
"ringfencing" transaction. The ringfencing complied with credit rating agency
criteria, enabling PG&E NEG, PG&E GTN, and PG&E ET to receive or retain their
own credit ratings based on their own creditworthiness. The ringfencing
involved the creation or use of special purpose entities (SPEs) as intermediate
owners between PG&E Corporation and its non-CPUC regulated subsidiaries. These
SPEs are: PG&E National Energy Group, LLC, which owns 100% of the stock of PG&E
NEG; PG&E GTN Holdings, LLC, which owns 100% of the stock of PG&E GTN; and PG&E
Energy Trading Holdings, LLC, which owns 100% of the stock of PG&E Corporation's
energy trading subsidiaries, PG&E Energy Trading-Gas Corporation, PG&E Energy
Trading Holdings Corporation, and PG&E Energy Trading-Power, L.P. In addition,
PG&E NEG's organizational documents were modified to include the same structural
elements as the SPEs to meet credit rating agency criteria. Ringfencing was
undertaken to enable PG&E NEG and various of its affiliates to obtain or
maintain investment grade ratings. The SPEs require unanimous approval of their
respective boards of directors, including an independent director, before they
can (a) consolidate or merge with any entity, (b) transfer substantially all of
their assets to any entity, or (c) institute or consent to bankruptcy,
insolvency, or similar proceedings or actions. The SPEs may not declare or pay
dividends unless the respective board of directors has unanimously approved such
action and the company meets specified financial requirements.
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.
49
PG&E Corporation Consolidated
Net cash provided by PG&E Corporation's operating activities totaled $682
million and $1,062 million for the quarters ended March 31, 2001 and 2000,
respectively. The decrease of $380 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 $499 million during the quarter ended
March 31, 2001, compared with $240 million used during the same quarter for
2000. In 2001, the primary use of cash for investing activities was $352
million for additions to property, plant, and equipment, compared with $321
million used for similar purposes in 2000.
Cash Flows from Financing Activities
- ------------------------------------
Cash used in financing activities for the quarter ended March 31, 2001, was
$432 million compared with $843 million used for the same quarter 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 $843 million used in 2000 resulted
from reduced borrowings of $547 million and a dividend payments of $108 million.
Utility
The following section discusses the Utility's significant cash flows from
operating, investing, and financing activities for the three-month period ended
March 31, 2001.
Cash Flows from Operating Activities
- ------------------------------------
Net cash provided by the Utility's operating activities totaled $520 million
and $688 million for the quarters ending March 31, 2001 and 2000, respectively.
The decrease of $168 million between 2001 and 2000 is primarily attributable to
high energy costs offset by partial cash payment of these costs, and a tax
refund received in the first quarter of 2001.
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 three-month
ended March 31, 2001, was $284 million.
Cash Flows from Financing Activities
- ------------------------------------
During the three months ended March 31, 2001, the Utility did not declare any
preferred or common stock dividends, compared with a payment of dividends on its
common stock of $122 million, for the quarter March 31, 2000. The Utility has
suspended payment of its common and preferred dividends due
50
to the negative impact on its financial condition from the ongoing energy
crisis. 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, Inc.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during the three months ended March 31, 2001, totaled $187 million.
Of this amount, $75 million related to the Utility's rate reduction bonds
maturing, $93 million related to mortgage bonds maturing and $19 million related
to the maturities and redemption of various of the Utility's medium-term notes
and other debt.
The Utility maintained a $1 billion revolving credit facility, which was due
to expire in 2002. However 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. The total defaulted
commercial paper outstanding at March 31, 2001, backed by this facility, was
$873 million. At March 31, 2001, the Utility had drawn and had outstanding $938
million under this facility to repay maturing commercial paper.
There was no new long-term debt issued in the period ended March 31, 2001. In
addition, there was no additional commercial paper issued during this same
period.
Due to the bankruptcy filing, the Utility is unable at this time to repay
unsecured pre-petition creditors. On May 1, 2001, the Utility did not make
interest payments on the following unsecured debt: pollution loan control
agreements, the 7.375% senior notes, and the $1.2 billion floating rates notes.
The Utility received notice that another $100 million pollution control bond
loan will be redeemed on May 18, 2001. Due to events of default under the credit
agreement with a letter of credit, on April 27, 2001, the bank accelerated a
pollution control loan and the $149 million loan was redeemed. In May 2001,
three other letter of credit banks accelerated and redeemed pollution control
loans totaling $305 million. All of these redemptions were funded by the letter
of credit banks resulting in like obligations from the Utility to the banks.
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.
PG&E National Energy Group
General
- -------
51
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
investment. Some of the projects in which PG&E NEG has an interest have been
financed primarily with non-recourse debt that is repaid from the project's cash
flows. This debt is often secured by interests in the physical assets, major
project contracts and agreements, cash accounts, and, in some cases, the
ownership interest in that project subsidiary. These financing structures are
designed to ensure that PG&E NEG is not contractually obligated to repay the
project subsidiary debt; that is, they are "non-recourse" to PG&E NEG and to its
subsidiaries not involved in the project. However, PG&E NEG has agreed to
undertake financial support for some of its project subsidiaries in the form of
limited obligations and contingent liabilities such as guarantees of specified
obligations. To the extent PG&E NEG becomes liable under these guarantees or
other agreements in respect of a particular project, it may have to use
distributions it receives from other projects to satisfy these obligations.
Cash Flows from Operating Activities
- ------------------------------------
During the three months ended March 31, 2001, PG&E NEG used net cash of $179
million in operating activities. The decrease in operating cash was driven
primarily by an increase in margin deposits related to its trading activities.
Cash Flows from Investing Activities
- ------------------------------------
During the three months ended March 31, 2001, PG&E NEG used net cash of $79
million in investing activities. PG&E NEG's cash outflows from investing
activities were primarily attributable to capital expenditures on generating
projects in construction and development.
Cash Flows from Financing Activities
- ------------------------------------
Net cash used in financing activities was $33 million for the three months
ended March 31, 2001. Net cash used in financing activities resulted from
repayment of long-term debt of $49 million, partially offset by net borrowings
under credit facilities.
RESULTS OF OPERATIONS
The table shows for the quarter ended March 31, 2001 and 2000, certain items
from our 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 these group.) The information for PG&E
Corporation (the "Total" column) includes the appropriate intercompany
elimination. Following this table we discuss our results of operations.
52
PG&E National Energy Group
------------------------------------------------
Integrated Interstate NEG Other &
Total Energy and Pipeline Elimini- Elimi-
(in millions) Utility NEG Marketing Operations nations nations(2) Total
------- ----- ---------- ---------- -------- ---------- -------
For the three months ended March 31, 2001
Operating revenues $ 2,562 $4,208 $4,152 $ 65 $ (9) $ (95) $ 6,675
Operating expenses 3,982 4,123 4,099 25 (1) (90) 8,015
Operating loss (1,340)
Interest income 35
Interest expense 247
Other income (expense), net (9)
Income taxes (610)
Net loss $ (951)
Net cash provided by operating activities 682
Net cash used by investing activities (499)
Net cash used by financing activities (432)
EBITDA(2) $(1,365) $ 128 $ 84 $ 51 $ (7) $ (9) $(1,246)
For the three months ended March 31, 2000(3)
Operating revenues $ 2,218 $2,823 $2,533 $ 282 $ 8 $ (33) $ 5,008
Operating expense 1,648 2,712 2,473 231 8 (28) 4,332
Operating loss 676
Interest income 24
Interest expense 183
Other income (expense), net (9)
Income taxes 228
Net income $ 280
Net cash provided by operating activities 1,062
Net cash used by investing activities (240)
Net cash used by financing activities (843)
EBITDA(2) $ 864 $ 142 $ 84 $ 58 $ - $ (8) $ 1,014
(1) Net income on intercompany positions recognized by segments using mark-to-
market accounting is eliminated. Intercompany transactions are also
eliminated.
(2) EBITDA is defined as income before provision for income taxes, interest
expense, interest income, deferred electric procurement costs, depreciation
and amortization, provision for loss on generation-related assets and
undercollected purchased power costs. 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 the 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 analysis, investors, and other interested parties.
However, EBITDA as presented herein may not be comparable to similarly
titled measures reported by other companies.
(3) Segment information for the prior period has been restated to conform with
new segment presentation (see Note 9 of the Notes to the Condensed
Consolidated Financial Statements).
53
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, 3, and 4 of the Notes to the Condensed
Consolidated Financial Statements for more information on the California energy
crisis.
PG&E Corporation incurred a net loss for the quarter ended March 31, 2001 of
$951 million from net income of $280 million for the same period in 2000. Of
the $1,231 million decrease, the Utility's net loss allocated to common stock
for the quarter ended March 31, 2001 accounted for $1,228 million of the
decrease
The decrease in performance in the first quarter 2001 compared to 2000 results
of operations is attributable to the following factors:
. The Utility's earnings were impacted as a result of the its
undercollected purchased power costs ($1.1 billion, after taxes).
Because of the lack of a regulatory, legislative, or judicial solution
to the California energy crisis, the Utility cannot defer for future
recovery its uncollected purchased power costs. These cost have been
expensed as incurred during the first quarter.
. 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 March 31, 2001. California law does not permit
carrybacks of such losses and only permits carryforwards of 55% of
such losses. As a result, PG&E Corporation was unable to recognize
$33 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
financial position. The incremental costs of these borrowings was $46
million, after-tax, for the first quarter of 2001.
. PG&E Pipeline's earnings increased $6 million versus the prior year's
first quarter because of higher short-term firm revenues, reflecting a
high capacity load factor and strong pricing fundamentals on gas
transportation to the California and Pacific Northwest gas market.
The effective tax rate for PG&E Corporation was 39.1% in 2001. PG&E
Corporation has been unable to recognize the entire tax benefit of the loss
carry forward in California described above.
54
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, Inc. Until its
financial condition is restored, the Utility is precluded from paying dividends
to PG&E Corporation and PG&E Holdings, Inc.
Utility
Overall Results
- ---------------
The Utility's first quarter net loss was $994 million in 2001 as compared to
the prior year's first quarter net income of $234 million. The decrease was
primarily the result of the $1.9 billion charge to earnings for undercollected
wholesale purchased power costs in excess of the amounts provided in customer
rates for recovery of such costs. The undercollected amounts includes ISO costs
incurred during the first quarter of 2001. Financial reporting standards
require that the amounts be accounted for as expenses unless they can be deemed
probable of recovery. Due to uncertainty created by the energy crisis, the
Utility cannot meet the accounting probability standard.
Operating Income
- ----------------
There was an operating loss of $1,420 million for the first quarter of 2001 as
compared to operating income of $570 million for the first quarter of 2000.
This decrease is due to the charge to earnings for undercollected wholesale
purchased power costs discussed above.
Operating Revenues
- ------------------
55
The Utility's operating revenues in the first quarter were $2.6 billion in
2001 as compared to operating revenues of $2.2 billion in 2000. Gas revenues
increased $686 million while electric revenues decreased $342 million. The
increase in gas revenues was primarily due to increased revenues from
residential customers due to higher gas billing rates resulting from high
natural gas prices and increased usage due to cooler temperatures in the first
quarter of 2001.
The decrease in electric revenues of $342 million was primarily due to credits
issued to direct access customers (resulting from higher wholesale power market
prices) and due to the reduction of revenue resulting from the CPUC's March 27,
2001, order (which was retroactive to January 16, 2001) that a portion of the
Utility's revenues be remitted to the DWR in compensation for the DWR's
electricity purchases. See Note 2 of the Notes to the Condensed Consolidated
Financial Statements for a discussion of the March 27, 2001, order and direct
access credits. These decreases were partially offset by increased revenue from
the Utility's 1.0 cent per kWh surcharge implemented on January 4, 2001.
Direct access credits are provided to customers that procure electricity from
independent generators under long-term contracts and receive a credit on their
utility bills at prevailing market prices. In accordance with CPUC regulations,
the Utility provides an energy credit to those customers (known as direct access
customers) who have chosen to buy their electric generation energy from an
energy service provider (ESP) other than the Utility. The Utility bills direct
access customers based upon fully bundled rates (generation, distribution,
transmission, public purpose programs, and a competition transition charge).
However, the direct access customer receives an energy credit equal to the
average market prices multiplied by customer energy usage for the period, with
the customer being obligated to their ESP at their direct access contract rate.
For the three-month period ending March 31, 2001, the estimated total of
accumulated credits for direct access customers that have not been paid by the
Utility is approximately $322 million. Such amounts are reflected on the
Utility's condensed consolidated balance sheet. 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 FERC.
Operating Expenses
- ------------------
The table below summarizes the changes in the Utility's operating expenses:
Three months
ended March 31,
-------------------- Increase Increase
2001 2000 (Decrease) (Decrease)
------ ------ ---------- ----------
(in millions)
Cost of electric energy, net $2,427 $ 513 $1,914 373%
Cost of gas 916 283 633 224%
Operating and maintenance 574 551 23 4%
Depreciation, amortization, and
decommissioning 65 301 (236) (78%)
------ ------ ------ ---
Total operating expenses $3,982 $1,648 $2,334 142%
====== ====== ====== ===
56
The Utility's operating expenses increased to a total of $4 billion in 2001
compared to a total of $1.6 billion in the first quarter of 2000. The overall
increase in operating expenses is primarily attributable to the Utility's $1.9
billion charge to earnings for undercollected wholesale purchased power costs as
described above. In addition, operating expenses increased due to the ongoing
increases in the cost of gas, with the average costs reaching $9.24 per DTh in
March 2001 compared to $2.27 per DTh in March 2000. Wholesale electric energy
costs in excess of the revenue for the generation component of frozen rates were
reflected as deferred electric procurement costs in 2000.
The decrease of $236 million in depreciation expenses for the three months
ended March 31, 2001 and 2000, respectively, is attributable to the utility no
longer recording amortization of generation-related transition costs. In
December 2000, the Utility wrote off these remaining generation related
transition costs.
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, Inc.
PG&E National Energy Group
Operating Income
- ----------------
Operating income at PG&E NEG decreased $26 million in the first quarter of
2001 as compared to 2000, primarily related to income from a portfolio
management transaction in 2000, and the disposition of the Texas operation in
late 2000. This decrease was partially offset by favorable results in the
merchant plants attributable to higher prices in the Northeast. Long-Term
Contract Plants benefited from higher prices in the Mid-Atlantic region.
PG&E Pipeline earnings increased as a result of higher short-term firm revenues.
Operating Revenues
- ------------------
PG&E NEG operating revenues increased $1,385 million in 2001 compared to 2000.
The increase is a result of increased commodity sales as PG&E NEG has focused
its trading efforts on asset management and higher-margin trades. In addition,
increases in the price of power and gas and the higher short-term firm revenues
described above have resulted in increased revenues. These increases were
partially offset by a decrease in Interstate Pipeline Operations revenues as a
result of the sale of the Texas operations in late 2000.
Operating Expenses
- ------------------
57
Operating expenses at PG&E NEG increased $1,411 million in 2000 compared to
the prior year. The increase results from the increases in the cost of power
and gas, partially offset by lower cost of sales and other operating expenses at
PG&E Pipeline reflective of the disposal of the Texas assets.
Dividends
- ---------
PG&E NEG currently intends to retain any future earnings to fund the
development and growth of its business. Further, PG&E NEG is precluded from
paying dividends, unless it meets certain financial tests. Therefore, it is not
anticipating paying any cash dividends on its common stock in the foreseeable
future.
REGULATORY MATTERS
A significant portion of PG&E Corporation's operations is regulated by federal
and state regulatory commissions. These commissions oversee service levels and,
in certain cases, PG&E Corporation's revenues and pricing for its regulated
services.
The Utility is the only subsidiary with significant regulatory proceedings at
this time. The Utility's significant regulatory proceedings are discussed below.
Regulatory proceedings associated with electric industry restructuring are
discussed above in "The California Energy Crisis." See Note 2 of the Notes to
the Condensed Consolidated Financial Statements.
The Utility's 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.
The CPUC's final decision in the Utility's 1999 GRC application increased annual
electric distribution revenues by $163 million and annual gas distribution
revenues by $93 million over 1998 authorized base revenues.
In March 2000, two interveners filed applications for rehearing of the 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
58
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 "ring fence" 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 past violations must be
reclassified as adjudicatory. A ruling is expected on May 14, 2001.
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 cannot 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
59
its report on the Utility's request, recommending that the CPUC deny the
Utility's request and order that the Utility refund directly to ratepayers
approximately $23 million accumulated during 1999 and 2000 in the Utility's
Vegetation Management Balancing Account. The Utility believes that ORA's
recommendations are unjustified and intends to challenge those recommendations
in hearings scheduled to commence on June 6, 2002. Further, the Utility had
proposed to return the approximately $23 million as a credit to the Utility's
TRA in which undercollected power purchase costs are recorded.
The Utility's Cost of Capital Proceedings
- -----------------------------------------
Each year, the Utility files an application with the CPUC to determine the
authorized rate of return that the Utility may earn on its electric and gas
distribution assets and recover from ratepayers. Since February 17, 2000, the
Utility's adopted return on common equity (ROE) has been 11.22% on electric and
gas distribution operations, resulting in an authorized 9.12% overall rate of
return (ROR). The Utility's earlier adopted ROE was 10.6%. In May 2000, the
Utility filed an application with the CPUC to establish its authorized ROR for
electric and gas distribution operations for 2001. The application requests an
ROE of 12.4%, and an overall ROR of 9.75%. If granted, the requested ROR would
increase electric distribution revenues by approximately $72 million and gas
distribution revenues by approximately $23 million. The application also
requests authority to implement an Annual Cost of Capital Adjustment Mechanism
for 2002 through 2006 that would replace the annual cost of capital proceedings.
The proposed adjustment mechanism would modify the Utility's cost of capital
based on changes in an interest rate index. The Utility also proposes to
maintain its currently authorized capital structure of 46.2% long-term debt,
5.8% preferred stock, and 48% common equity. In March 2001, the CPUC issued a
proposed decision recommending no change to the current 11.22% ROE for test year
2001. This authorized ROE results in a corresponding 9.12% return on rate base
and no change in the Utility's electric or gas revenue requirement for 2001. A
final CPUC decision is pending.
The Utility's FERC Transmission Rate Cases
- ------------------------------------------
Electric transmission revenues, and both wholesale and retail transmission
rates are subject to authorization by the FERC. The FERC has not yet acted upon
a settlement filed by the Utility that, if approved, would allow the Utility to
recover $391 million in electric transmission rates for the 14-month period of
April 1, 1998 through May 31, 1999. During this period, somewhat higher rates
have been collected, subject to refund. A FERC order approving this settlement
is expected by the end of 2001. The Utility has accrued $29 million for
potential refunds related to the 14-month period ended May 31, 1999. In April
2000, the FERC approved a settlement that permits the Utility to recover $298
million in electric transmission rates retroactively for the 10-month period
from May 31, 1999 to March 31, 2000. The Utility has accrued $9 million for
potential refunds relating to this period. 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 November 2000, the FERC accepted, subject to refund,
60
the Utility's proposal to collect $298 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 owed to the Utility
from the ISO for congestion 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. The Utility currently
estimates that if FERC grants its request, it will collect from Western an
additional $1.125 billion 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 8 of the Notes to the Consolidated
Financial Statements for further discussion of environmental matters.
Utility
- -------
The Utility records an environmental remediation liability when site
assessments indicate remediation is probable and a range of reasonably likely
clean-up costs can be estimated. The Utility reviews its remediation liability
quarterly for each identified site. The liability is an estimate of costs for
site investigations, remediation, operations and maintenance, monitoring, and
site closure. The remediation costs also reflect (1) current technology, (2)
enacted laws and regulations, (3) experience gained at similar sites, and (4)
the probable level of involvement and financial condition of other potentially
responsible parties. Unless there is a better estimate within this range of
possible costs, the Utility records the lower end of this range.
At December 31, 2000, the Utility expects to spend $320 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 $462 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
61
to be responsible for clean-up costs at additional sites or expected outcomes
change.
The Utility had an environmental remediation liability of $307 million and
$307 million at March 31, 2001 and December 31, 2000, respectively. The $320
million accrued at March 31, 2001 includes (1) $139 million related to the pre-
closing remediation liability, associated with divested generation facilities
(see further discussion in the "Generation Divestiture" section of Note 2 of the
Notes to the Condensed Consolidated Financial Statements), and (2) $168 million
related to remediation costs for those generation facilities that that Utility
still owns, manufactured gas plant sites, and gas gathering compressor stations.
Of the $307 million environmental remediation liability, the Utility has
recovered $193 million through rates, and expects to recover another $84 million
future rates. The Utility is seeking recovery of the remainder of its costs
from insurance carriers and from other third parties as appropriate.
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
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
62
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) and the U.S. Department of
Justice have 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, EPA visited both facilities. PG&E NEG believes this request for
information is part of EPA's industry-wide investigation of coal-fired plants'
compliance with the Clean Air Act requirements governing plant modifications.
PGE&NEG also believes that any changes made to the plants were routine
maintenance or repairs and, therefore, did not require permits. EPA has not
issued a notice of violation or filed any enforcement action against PG&E NEG at
this time. Nevertheless, if EPA disagrees with PG&E NEG's conclusion with
respect to the changes 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.
In addition to the EPA, states may impose more stringent air emissions
requirements. On May 11, 2001, the Massachusetts Department of Environmental
Protection issued regulations imposing restictions on certain air emissions from
existing coal-fired power plants. These requirements will primarily impact PG&E
NEG's Salem Harbor and Brayton Point generating facilities. Through 2008, it may
be necessary to spend approximately $265 million to comply with these
regulations. In addition, with respect to approximately 600 megawatts (MW) (or
about 12%) of PG&E NEG's New England capacity, it may be necessary to implement
fuel conversion, limit operations, or install additional environmental controls.
PG&E Gen's existing power plants, including USGenNE facilities, are subject to
federal and state water quality standards with respect to discharge constituents
and thermal effluents. Three of the fossil-fueled plants owned and operated by
USGenNE are operating pursuant to NPDES permits that have expired. For the
facilities whose NPDES permit have expired, permit renewal applications are
pending, and it is anticipated 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 USGenNE's cost to comply with the new
permit conditions could be as much as $60 million through 2005. It is possible
that the new permits may contain more stringent limitations than prior permits.
During September 2000, USGenNE signed a series of agreements that require,
among other things, USGenNE to alter its existing waste water
63
treatment at two 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 expected cost of
these improvements, which are underway, is $21 million.
PG&E NEG anticipates spending up to approximately $330 million, net of
insurance proceeds, through 2008, for environmental compliance at currently
operating facilities, which primarily addresses: (a) new Massachusetts air
regulations made public on April 23, 2001 affecting Brayton Point and Salem
Harbor Stations; (b) wastewater permitting requirements that may apply to
Brayton Point, Salem harbor and Manchester Street Stations; and (c) requirements
that are reflected in a consent decree concerning wastewater treatment
facilities at Salem Harbor and Brayton Point stations.
PRICE RISK MANAGEMENT ACTIVITIES
We have established a risk management policy that allows 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 hedging purposes primarily to offset PG&E Corporation's or
the Utility's primary market risk exposures, which include commodity price risk,
interest rate risk, and foreign currency risk. We also use derivatives,
including those used for 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 not hedged) often exist or are established due to
PG&E Corporation's and the Utility's assessment of their responses to changing
market conditions. To the extent that PG&E Corporation has an open position, it
is exposed to the risk that fluctuating market prices may adversely impact its
financial results.
PG&E Corporation and the Utility 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
64
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.
Price risk management strategies 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 load. 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.
In response to high wholesale electricity costs experienced during the summer
of 2000, the CPUC in August 2000 eliminated the requirement to procure
electricity in the spot market and authorized the Utility to enter into
"bilateral agreements" with third parties. These contracts are used to purchase
electricity from non-PX sources at fixed prices for terms that may extend to the
end of 2005. The purpose of bilateral contracts is to lock in supply and rates
on the future purchase of electricity and to reduce price volatility.
The CPUC has authorized the Utility to trade natural gas-based financial
instruments to manage price and revenue risks associated with its natural gas
transmission and storage assets, subject to certain conditions. Furthermore,
the Utility was authorized to trade natural gas-based financial instruments to
hedge the gas commodity price risks in serving core gas customers.
PG&E Corporation's business units measure commodity price risk exposure using
value-at-risk and other methodologies that simulate future price movements in
the energy markets to estimate the size and probability of future potential
losses. We quantify market risk using a variance/co-variance value-at-risk
model that provides a consistent measure of risk across diverse energy markets
and products. The use of this methodology requires a number of important
assumptions, including the selection of a confidence level for losses,
volatility of prices, market liquidity, and a holding period.
PG&E Corporation uses historical data for calculating the price volatility of
our contractual positions and how likely the prices of those positions will move
together. The model includes all derivatives and commodity investments in our
trading portfolios and only derivative commodity investments for our non-trading
portfolio (but 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's portfolios will incur a loss in one day greater than its value-at-
risk. The value-at-risk is aggregated for PG&E Corporation by correlating the
daily returns of the portfolios for electricity and natural gas for the previous
22 trading days.
65
PG&E NEG's daily value-at-risk commodity price risk exposure as of March 31,
2001, was $11.5 million for trading activities and $8.8 million for non-trading
activities. The Utility's daily value-at-risk commodity price risk exposure as
of March 31, 2001, was $11.8 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.
Interest Rate Risk
- ------------------
PG&E Corporation, primarily through PG&E NEG, uses interest rate swaps to
manage fluctuations in cash flows resulting from their interest rate exposure.
PG&E Corporation evaluates both the short-term and long-term interest rate
exposures and considers its overall corporate finance objectives when
considering proposed hedges. PG&E Corporation does not enter into interest rate
derivatives instruments for other than hedging purposes.
PG&E Corporation is exposed to the following types of interest rate risk and
the strategies used to manage this risk are as described below:
Floating rate exposure measures the sensitivity of corporate earnings and cash
flows to changes in short-term interest rates. This exposure arises when short-
term debt is rolled over at maturity, when interest rates on floating rate notes
are periodically reset according to a formula or index, and when floating rate
assets are financed with fixed rate liabilities. PG&E Corporation manages its
exposure to short-term interest rates by using an appropriate mix of short-term
debt, long-term floating rate debt, and long-term fixed rate debt.
Financing exposure measures the effect of an increase in interest rates that
may occur related to any planned or expected fixed rate debt financing. This
includes the exposure associated with replacing debt at maturity. PG&E
Corporation will hedge financing exposure in situations where the potential
impairment of earnings, cash flows, and investment returns or execution
efficiency, or external factors (such as bank imposed credit agreements)
necessitate hedging.
Refunding exposure measures the effect of an increase in interest rates on the
ability to economically refund a callable debt instrument. Corporate bonds
typically are issued with a call feature that allows the issuer to retire and
replace the bonds at a lower rate if interest rates have fallen. The value of
this call feature to the issuer declines with increases in interest rates. PG&E
Corporation will hedge refunding exposure when it is economic to repurchase all
or part of the underlying debt instrument and replace it with a debt instrument
that has lower cost during its remaining life. The guideline for a refunding to
be economic is that the net present value savings should exceed 5% of the par
value of the debt to be refunded and the refunding efficiency should exceed 85%.
Interest rate risk sensitivity analysis is used to measure PG&E Corporation's
interest rate price risk by computing estimated changes in
66
the fair value in the event of assumed changes in market interest rates. As of
March 31, 2001, if interest rates had averaged 1% higher, estimated losses would
have increased by approximately $25 million for PG&E Corporation and estimated
losses would have increased by approximately $17 million for the Utility.
Foreign Currency Risk
- ---------------------
PG&E Corporation's objective is to manage foreign currency exposure that may
impact its cash flows, corporate earnings, and investment returns as a result of
currency exchange rate movements.
PG&E Corporation is exposed to the following types of foreign currency risk
and the strategies used to manage this risk are as described below:
Economic exposure measures the change in value that results from changes in
future operating or investing cash flows caused by the timing and level of
anticipated foreign currency flows. Economic exposure includes the anticipated
purchase of foreign entities, anticipated cash flows, projected revenues and
expenses denominated in a foreign currency.
Transaction exposure measures changes in value of current outstanding
financial obligations already incurred, but not due to be settled until some
future date. This includes the agreement to purchase a foreign entity in a
currency other than the U.S. dollar, an obligation to infuse equity capital into
a foreign entity, foreign currency denominated debt obligations, as well as
actual non-U.S. dollar cash flows such as dividends declared but not yet paid.
Translation exposure measures potential accounting derived changes in owners'
equity that result from translating a foreign affiliate's financial statements
from its functional currency to U.S. dollars for PG&E Corporation's consolidated
financial statements.
PG&E Corporation's primary foreign currency exchange rate exposure was with
the Canadian dollar. The following instruments are used to hedge foreign
currency exposures: forwards, swaps, and options. Based on a sensitivity
analysis at March 31, 2001, a 10% devaluation of the Canadian dollar would be
immaterial to PG&E 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 5 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 non-hedging and hedging purposes.
Additionally, we may engage in hedging activities using futures, options, and
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies. (See Risk Management Activities,
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. Since the
filing, the Bankruptcy Court has approved various requests by the Utility to
permit the Utility to carry on its normal business operations (including payment
of employee wages and benefits, refunds of certain customer deposits, use of
certain bank accounts, and use cash collateral) and to fulfill certain post-
petition obligations to suppliers and creditors.
Under the Bankruptcy Code, for the first 120 days after the initial filing,
the debtor has the exclusive right to file with the Bankruptcy Court a plan of
reorganization that specifies the treatment of claims. After the initial 120-
day period (and any extensions of the period granted by the court) creditors and
other parties in interest may file their own plan of reorganization. The
Utility intends to file a plan of reorganization within the 120-day period,
subject to the uncertainties inherent in the bankruptcy proceedings.
In addition, a number of QFs have 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. Before the Utility filed its Chapter 11 petition, some QFs
filed complaints in various state courts asking the court to terminate or
suspend their contracts with the Utility. The Utility believes these actions
have been automatically stayed.
Under the Bankruptcy Code, the Utility has the right to reject or assume
executory contracts (contracts that require future performance). If the court
terminates or suspends the QF contracts or if the Utility rejects the contracts,
the amount of the Utility's net open position will increase. If the contracts
are not suspended and are ultimately assumed by the Utility, the Utility would
be obligated to continue paying the power prices called for under the contract
even when market prices are lower.
On April 9, 2001, the Utility also filed a complaint in the Bankruptcy Court
against the CPUC and its Commissioners requesting that the court declare that
any attempt by the CPUC to implement or enforce the regulatory accounting
changes approved by the CPUC on March 27, 2001 would violate the automatic stay
imposed by bankruptcy law, and asking the court to enjoin implementation or
enforcement of such accounting changes. As previously disclosed, the accounting
changes would require the Utility to restate all of its regulatory books and
accounts retroactive to January 1, 1998, the effect of which would be to prolong
the electric rate freeze and transform the Utility's under-collected wholesale
power costs into generation-related
69
transition costs. The CPUC has filed a motion to dismiss the Utility's complaint
and/or for summary judgment. A hearing is set for May 14, 2001, to consider the
Utility's request for a preliminary injunction and the CPUC's motion.
On April 20, 2001, the Utility filed a cash flow forecast that indicated that
based on projected revenues from approved rates, current regulatory rules, and
expected outlays, the Utility projected that it expects to have adequate
revenues over the next six months to pay its future operating costs, including
ongoing payments to QFs and payments presently required to be made to the DWR.
A critical assumption in the forecast is that DWR purchases the full net open
position for the Utility's customers and that the ISO no longer charges the
Utility for any costs other than those attributable to the Utility's own
generation resources.
On May 2, 2001, the Utility filed a complaint for injunctive and declaratory
relief in the United States Bankruptcy Court asking the court to prohibit the
California Independent System Operator (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 concerning credit standards and ordered that the ISO
could only buy power on behalf of creditworthy entities. The Utility has not
been a creditworthy company under 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.
In its complaint, the Utility 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. In addition, the complaint seeks a permanent injunction
prohibiting the ISO from taking such actions.
In addition, continuing to charge the Utility for such purchases is
potentially reducing the value of the Utility's assets significantly, depending
on the average retail rate, the wholesale price the ISO has paid for real-time
power, and the amount of power purchased by the DWR. The Utility estimates that,
if the ISO's actions are not stayed or enjoined, the Utility also would incur
costs associated with the DWR's pro rata share of ancillary services and other
costs associated with the ISO's procurement of power from third parties unless
the ISO were to allocate these other costs to, and bill, the DWR. At present,
the Utility does not believe that the ISO is allocating any of these costs to
the DWR, or billing the DWR for any such costs.
Among other allegations, the Utility's complaint alleges that requiring the
Utility to pay more than it can collect in its existing generation-related rates
would be improper under the federal Bankruptcy Code because it is not in the
best interest of the bankruptcy estate, would be an unauthorized post-petition
use of the Utility's property, and if allowed to continue, would jeopardize the
administration of the bankruptcy estate and the Utility's ability to reorganize.
The Utility believes the ISO is
70
violating its own tariff, as well as FERC orders and federal bankruptcy law by
continuing to purchase power on behalf of the Utility.
The United States Bankruptcy Trustee has appointed a ratepayers'committee
composed of business representatives, members of government agencies,and
consumer groups. As a party to the proceedings, the ratepayers' committee
would be entitled to investigate the Utility's plan of reorganization and offer
alternatives. On May 9, 2001, the Utility filed a motion with the Bankruptcy
Court asking the court to vacate the Trustee's appointment of the ratepayers'
committee because the creation of the committee is not authorized by the
Bankruptcy Code. Under the Bankruptcy Code, only creditors and equity security
holders are eligible for appointment to a committee by the Trustee. 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.
The first meeting of creditors is scheduled for June 7, 2001. The last day
for creditors to file proofs of claim is September 5, 2001.
Pacific Gas and Electric Company v. California Public Utilities Commissioners
- -----------------------------------------------------------------------------
As described in 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, the
Utility filed a lawsuit against the Commissioners of the California Public
Utilities Commission (CPUC), currently pending in the United States District
Court for the Central District of California, asking the court to declare that
the federally approved wholesale power costs the Utility has incurred to serve
its customers are recoverable in retail rates.
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 PG&E was
challenging are non-final interim orders that will only become final upon a
grant or denial of rehearing.
Finding in the Utility's favor, the court ruled that:
(i) the Utility's prior state court proceedings challenging the CPUC's October
21, 1999 post-transition-period ratemaking decision on state law grounds did not
bar the Utility's federal claims, because the Utility had properly reserved its
federal claims in its petition to the California Supreme Court, and because the
Utility had not litigated the federal claims in the state court.
(ii) Federal court jurisdiction over the Utility's preemption claim was proper.
(iii) The court need not stay or dismiss the Utility's case in deference to the
ongoing CPUC proceedings.
(iv) The Johnson Act, which generally precludes federal courts from enjoining
state utilities commission rate orders, did not apply to the
71
Utility's action because the Utility had pleaded a claim that federal law
preempted state law, which does not fall under the terms of the statute.
(v) The Utility's case need not be dismissed with prejudice based on the CPUC's
asserted sovereign immunity under the Eleventh Amendment to the U.S.
Constitution, because the Eleventh Amendment does not bar an action, such as the
Utility's, to enjoin state officers from violating federal law.
Wilson vs. PG&E Corporation and Pacific Gas and Electric Company
- ----------------------------------------------------------------
As described in 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, two
complaints were filed against PG&E Corporation and Pacific Gas and Electric
Company 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").
PG&E Corporation and the Utility believe these complaints to be without merit.
As previously disclosed, the Utility filed a 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.
Compressor Station Chromium Litigation
- ---------------------------------------
As described in 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, several
suits are pending in California courts against the Utility. One of these suits
also names PG&E Corporation as a defendant. On May 2, 2001, another complaint
entitled Boyd, et al. v. PG&E, et al., was filed in Los Angeles Superior Court
on behalf of 14 plaintiffs. The Utility has not been served yet. The complaint
alleges personal injuries, wrongful death, and loss of consortium, arising from
alleged exposure to chromium at the Utility's gas compressor stations located at
Hinkley and Kettleman, California. Plaintiffs seek compensatory and punitive
damages. The complaint does not name PG&E Corporation as a defendant.
There are now ten cases comprising the compressor station chromium litigation.
There are now approximately 1,160 plaintiffs in these cases. The Utility
believes that all ten cases have been stayed by the automatic stay provisions of
the Bankruptcy Code.
PG&E Corporation and the Utility believe that the ultimate outcome of this
matter will not have a material adverse effect on their financial condition or
results of operation.
Federal Securities Lawsuit
- --------------------------
On April 16, 2001, a complaint was filed against PG&E Corporation and Pacific
Gas and Electric Company in the federal court for the Central District of
California 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. The complaint alleges that
72
PG&E Corporation and the Utility violated federal securities laws, generally
acceptable 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 operation.
Item 2. Changes in Securities and Use of Proceeds
-----------------------------------------
The shares of PG&E NEG are owned directly by PG&E National Energy Group, LLC,
a Delaware limited liability company (NEG LLC). NEG LLC is wholly owned by PG&E
Corporation. As disclosed in a Current Report on Form 8-K filed by PG&E
Corporation with the Securities and Exchange Commission on March 2, 2001, in
connection with a two term loans obtained by PG&E Corporation from General
Electric Capital Corporation and Lehman Commercial Paper Inc., NEG LLC has
granted to affiliates of the lenders an option that entitles these affiliates to
purchase 2 to 3 percent of the shares of PG&E NEG depending on how long the
loans are outstanding, at an exercise price of $1.00. The percentage will be
calculated on a fully diluted basis as of the date of full repayment of the
loans. The option becomes exercisable on the date of full repayment or,
earlier, if an initial public offering of the shares of PG&E NEG (IPO) were to
occur. PG&E Corporation has granted to the holders of the option a further put
option under which the holders of the option have the right to require PG&E
Corporation to repurchase the option at a purchase price equal to the fair
market value of the underlying PG&E NEG shares, which right is exercisable at
any time after the earlier of full repayment of the loans or 45 days before
expiration of the option if an IPO has not occurred. The put option will expire
45 days after maturity of the loans. The issuance of the put option by PG&E
Corporation was not registered under the Securities Act of 1933 in reliance on
the exemption afforded by Section 4(2).
73
Item 3. Defaults Upon Senior Securities
-------------------------------
The Utility has authorized 75 million shares of First Preferred Stock ($25 par
value), which may be issued as redeemable or non-redeemable preferred stock. At
March 31, 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) and April 30, 2001
(normally payable May 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. The dividend for the three-month period ending January 31,
2001 became a dividend in arrears and, as such, will accumulate from period to
period. 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.
Accumulated and unpaid preferred stock dividends for the three-month period
ending January 31, 2001 amounted to $6 million.
As previously reported, the total defaulted commercial paper outstanding as of
May 10, 2001, was $873 million. As of May 10, 2001, the Utility had drawn and
had outstanding $938 million under the bank credit facility, which was also in
default.
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 and the Utility's filing of a petition for
reorganization under Chapter 11 of the
74
U.S. Bankruptcy Code. 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 May 10, 2001, the total principal of the bonds (and related
loans) accelerated and redeemed was $454 million. As of May 1, 2001, the Utility
did not make interest payments of $5 million on pollution control bonds series
96B-F and 97A-C. 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, on May 1,
2001, the Utility did not make interest payments on the 7.375% senior notes and
the $1.24 billion floating rate notes. As of May 1, 2001, the total arrearage
of these interest payments was $48 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 5. Other Information
-----------------
Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends
Pacific Gas and Electric Company's earnings to fixed charges ratio for the
three months ended March 31, 2001, was a negative 6.67. Pacific Gas and
Electric Company's earnings to combined fixed charges and preferred stock
dividends ratio for the three months ended March 31, 2001, was a negative 6.40.
The negative ratios of earnings to fixed charges and earnings to combined fixed
charges and preferred stock dividends indicates a deficiency in earnings of
$1,618 million and $1,618 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:
75
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
(b) The following Current Reports on Form 8-K were filed during the first
quarter of 2001 and through the date hereof (2):
1. January 4, 2001
Item 5. Other Events--California Energy Crisis
2. January 5, 2001
Item 5. Other Events--
California Public Utilities Commission Decision Issued
3. January 10, 2001
Item 5. Other Events--
A. Current Financial Condition
B. Impending Natural Gas Shortage
C. ISO's Requested Tariff Amendment to Creditworthiness Standards
4. January 10, 2001
Item 5. Other Events--Suspension of PG&E Corporation and Pacific Gas and
Electric Company Dividends
5. January 17, 2001
Item 5. Other Events--
A. Ratings Downgrades
B. Liquidity Impacts and Financial Condition
6. February 1, 2001
Item 5. Other Events--
A. Wholesale Power Payments
B. Liquidity Impacts and Financial Condition
C. Federal Lawsuit
D. Rate Stabilization Plan Proceeding
E. Consulting Report
F. CPUC Emergency Action
7. February 14, 2001
Item 5. Other Events--
A. Assembly Bill 1X
B. Liquidity Impacts and Financial Condition
C. Federal Lawsuit
8. February 28, 2001
Item 5. Other Events--
A. Recent Regulatory Action
B. Liquidity
76
C. Wilson vs. PG&E Corporation and Pacific Gas and Electric Company
9. March 2, 2001 - Filed by PG&E Corporation only
Item 5. Other Events-- PG&E Corporation debt restructure
10. March 9, 2001
Item 5. Other Events
A. Recent Regulatory Action
B. 2001 Cost of Capital Proceeding
11. March 16, 2001
Item 5. Other Events - Liquidity and Financial Condition
12. March 23, 2001
Item 5. Other Events
A. Recent Legislative and Regulatory Actions
B. Accounting Treatment
C. Bank Forbearance Agreement
13. March 30, 2001
Item 5. Other Events
A. Recent Regulatory Actions
B. Accounting Treatment
C. Liquidity and Financial Condition
14. April 6, 2001 (as amended) filed by PG&E Corporation only
Item 5. Other Events - Pacific Gas and Electric Company Bankruptcy
15. April 6, 2001 (as amended) filed by Pacific Gas and Electric Company
only
Item 3. Other Events - Bankruptcy or Receivership.
16. May 7, 2001 - filed by PG&E Corporation only
Item 9. Regulation FD Disclosure
17. May 8, 2001
Item 5. Other Events
A. Federal Lawsuit
B. Pacific Gas and Electric Company Bankruptcy
- ---------------
(2) Unless otherwise noted, all Current Reports on Form 8-K were filed
under both Commission File Number 1-12609 (PG&E Corporation) and
Commission File Number 1-2348 (Pacific Gas and Electric Company).
77
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 /s/ CHRISTOPHER P. JOHNS
----------------------------
CHRISTOPHER P. JOHNS
Vice President and Controller
(duly authorized officer and principal accounting
officer)
PACIFIC GAS AND ELECTRIC COMPANY
By /S/ DINYAR B. MISTRY
---------------------------
DINYAR B. MISTRY
Vice President and Controller
(duly authorized officer and principal
accounting officer)
Dated: May 14, 2001
78
Exhibit Index
Exhibit No. Description of Exhibit
11 Computation of Earnings Per Common Share
12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and ELectric Company
12.2 Computation of Ratios and Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company.