FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
----------------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31,June 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________to ___________
Exact Name of
Commission Registrant State or other IRS Employer
File as specified Jurisdiction of Identification
Number in its charter Incorporation Number
- ----------- -------------- --------------- --------------
1-12609 PG&E Corporation California 94-3234914
1-2348 Pacific Gas and California 94-0742640
Electric Company
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California 94177 San Francisco, California 94105
- ----------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Pacific Gas and Electric Company PG&E Corporation
(415) 973-7000 (415) 267-7000
- ----------------------------------------------------------------------
Registrant's telephone number, including area code
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding twelve months (or for such
shorter period that the registrant was required to file such reports),
and (2) have been subject to such filing requirements for the past 90
days.
Yes X No _________
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common Stock Outstanding May 9,July 28, 2000:
PG&E Corporation 385,326,805385,758,143 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PG&E CORPORATION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31,JUNE 30, 2000
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
CONDENSED CONSOLIDATED INCOME STATEMENT.................1
CONDENSED CONSOLIDATED BALANCE SHEET....................2
STATEMENT OF CONSOLIDATED INCOME........................1
CONSOLIDATED BALANCE SHEET..............................2
STATEMENT OFCONDENSED CONSOLIDATED CASH FLOWS ...................4.........4
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED INCOME STATEMENT.................5
CONDENSED CONDSOLIDATED BALANCE SHEET...................6
STATEMENT OF CONSOLIDATED INCOME........................5
CONDSOLIDATED BALANCE SHEET.............................6
STATEMENT OFCONDENSED CONSOLIDATED CASH FLOWS....................8FLOWS..........8
NOTE 1: GENERAL...........................................9
NOTE 2: THE CALIFORNIA ELECTRIC INDUSTRY.................10INDUSTRY..................9
NOTE 3: RISK MANAGEMENT AND FINANCIAL INSTRUMENTS........17
NOTE 4: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED DEBENTURES...........20DEBENTURES...........19
NOTE 5: DIVESTITURES.....................................20DIVESTITURES.....................................19
NOTE 6: COMMITMENTS AND CONTINGENCIES....................22CONTINGENCIES....................21
NOTE 7: SEGMENT INFORMATION..............................25INFORMATION..............................24
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS. ....................27
THE UTILITY...............................................29
PG&E NATIONAL ENERGY GROUP................................35
REGULATORY MATTERS........................................37
RESULTS OF OPERATIONS.....................................40OPERATIONS.....................................39
LIQUIDITY AND FINANCIAL RESOURCES.........................42RESOURCES.........................44
ENVIRONMENTAL MATTERS.....................................45MATTERS.....................................47
RISK MANAGEMENT ACTIVITIES................................45ACTIVITIES................................47
LEGAL MATTERS.............................................46MATTERS.............................................48
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................47RISK.........................................48
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.........................................48
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......48PROCEEDINGS.........................................49
ITEM 5. OTHER INFORMATION.........................................52INFORMATION.........................................49
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................52
SIGNATURE..........................................................54
8-K..........................49
SIGNATURE..........................................................51
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
PG&E CORPORATION
STATEMENT OF CONDENSED CONSOLIDATED INCOME STATEMENT
(in millions, except per share amounts)
Three months ended March 31,June 30, Six months ended June 30,
2000 1999 (1) --------- ---------2000 1999 (1)
-------- -------- -------- --------
Operating revenues
Utility $ 2,2182,296 $ 2,0852,233 $ 4,514 $ 4,318
Energy commodities and services 2,790 3,0413,342 2,449 6,132 5,490
-------- -------- -------- --------
Total operating revenues 5,008 5,1265,638 4,682 10,646 9,808
Operating expenses
Cost of energy for utility 796 6551,157 664 1,953 1,319
Cost of energy commodities and services 2,472 2,7973,047 2,224 5,519 5,021
Operating and maintenance, net 717 775743 754 1,460 1,529
Depreciation, amortization and decommissioning 347 43869 560 416 998
-------- -------- -------- --------
Total operating expenses 4,332 4,6655,016 4,202 9,348 8,867
-------- -------- -------- --------
Operating income 676 461622 480 1,298 941
Interest expense, net 183 201182 192 365 393
Other income, net 15 2112 40 27 61
-------- -------- -------- --------
Income before income taxes 508 281452 328 960 609
Income taxes 228 114204 132 432 246
-------- -------- -------- --------
Income from continuing operations 280 167248 196 528 363
Discontinued operations
Loss from operations of PG&E Energy Services
(net of applicable income taxes of
$7 million)$10 million and $17 million, respectively) - (8)(14) - (22)
-------- -------- -------- --------
Income before cumulative effect of change 248 182 528 341
in accounting principle 280 159
Cumulative effect of change in accounting
principle (net of applicable income taxes
of $8 million) - - - 12
-------- -------- -------- --------
Net Incomeincome $ 280248 $ 171182 $ 528 $ 353
======== ======== ======== ========
Weighted Average Common Shares Outstanding 361 373367 361 370
Earnings per common share, basic
Income from continuing operations $ .78.69 $ .45.53 $ 1.46 $ .98
Discontinued operations - (.02)(.03) - (.06)
Cumulative effect of accounting change - - - .03
-------- -------- Net income-------- --------
$ .78.69 $ .46.50 $ 1.46 $ .95
======== ======== ======== ========
Earnings per common share, diluted
Income from continuing operations $ .77.68 $ .39.50 $ 1.45 $ .90
Discontinued operations - (.02)(.03) - (.06)
Cumulative effect of accounting change - - - .03
-------- -------- Net income-------- --------
$ .77.68 $ .40.47 $ 1.45 $ .87
======== ======== ======== ========
Dividends declared per common share $ .30 $ .30 $ .60 $ .60
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part
of this statement.
(1) Amounts have been restated to reflect the change in accounting for major maintenance and
overhauls at the PG&E National Energy Group (see Note 1 of the Notes to the Condensed
Consolidated Financial Statements), and reclassification of PG&E Energy Services operating
results to discontinued operations. The accounting change resulted in a cumulative effect being
recorded as of January 1, 1999, of $12 million ($0.03 per share), net of income taxes of $8
million. The accounting change did not have a material effect on operating expenses during the
first quarter of 1999. Operating income previously reported for the firstsecond quarter of 1999 was $442$454 million.
Net income previously reported for the firstsecond quarter of 1999 was $156$180 million ($0.420.49 per share).
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
March 31,---------------------------
June 30, December 31,
2000 1999
------------ -----------
ASSETS
Current assets
Cash and cash equivalents $ 260307 $ 281
Short-term investments 4549 187
Accounts receivable
Customers, net 1,4591,569 1,486
Energy marketing 547954 532
Price risk management 434999 607
Inventories and prepayments 543660 598
Deferred income taxes 11182 133
-------- -------
Total current assets 3,3994,620 3,824
Property, plant, and equipment
Utility 23,18523,454 23,001
Non-utility
Electric generation 1,9061,965 1,905
Gas transmission 2,5492,537 2,541
Construction work in progress 458469 436
Other 119159 184
-------- -------
Total property, plant, and equipment (at original cost) 28,21728,584 28,067
Accumulated depreciation and decommissioning (11,573)(11,739) (11,291)
-------- --------
Net property,Property, plant, and equipment, 16,644net 16,845 16,776
Other noncurrent assets
Regulatory assets 4,9405,331 4,957
Nuclear decommissioning funds 1,3001,336 1,264
Other 2,9133,097 2,894
-------- --------
Total noncurrent assets 9,1539,764 9,115
-------- --------
TOTAL ASSETS $ 29,19631,229 $ 29,715
======== ========
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of
this statement.
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
March 31,---------------------------
June 30, December 31,
2000 1999
------------ -----------------------
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 9521,017 $ 1,499
Current portion of long-term debt 672579 592
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 6191,302 708
Other 367321 559
Regulatory balancing accounts 638574 384
Energy marketing 594991 480
Accrued taxes 529338 211
Price risk management 391947 575
Other 9971,075 1,033
-------- --------
Total current liabilities 6,0497,434 6,331
Noncurrent liabilities
Long-term debt 6,4686,535 6,673
Rate reduction bonds 1,9551,890 2,031
Deferred income taxes 3,0113,277 3,147
Deferred tax credits 222212 231
Other 3,6243,863 3,636
-------- --------
Total noncurrent liabilities 15,28015,777 15,718
Preferred stock of subsidiaries 480 480
Utility obligated mandatorily redeemable preferred securities of
trust holding solely utility subordinated debentures 300 300
Common stockholders' equity
Common stock, no par value, authorized 800,000,000 shares,
issued, 384,867,522385,394,484 and 384,406,113 shares, respectively 5,9165,928 5,906
Common stock held by subsidiary, at cost, 23,815,500 shares (690) (690)
Reinvested earnings 1,8612,000 1,670
-------- --------
Total common stockholders' equity 7,0877,238 6,886
Commitments and contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 29,19631,229 $ 29,715
======== ========
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of
this statement.
PG&E CORPORATION
STATEMENT OF CONDENSED CONSOLIDATED CASH FLOWS (in millions)
For the threesix months ended March 31,June 30,
2000 1999
---------- ----------
Cash flows from operating activities
Net income $ 280528 $ 171353
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization and decommissioning 347 438416 998
Deferred income taxes and tax credits-net (145) (178)111 (630)
Other deferred charges and noncurrent liabilities (9) (125)(369) (401)
Cumulative effect of change in accounting principle - (12)
Net effect of changes in operating assets and liabilities:
Short-term investments 142 21139 18
Accounts receivable - trade 12 333(505) 287
Regulatory balancing accounts payable 254 212190 606
Inventories and prepayments 55 97158 65
Price risk management assets and liabilities, net (11) (20) (4)
Accounts payable - trade (89) (167)594 (226)
Accrued taxes 318 223127 635
Other working capital (118) 101314 (56)
Other-net 26 (69)(8) 22
--------- ---------
Net cash provided by operating activities 1,062 1,0251,675 1,655
--------- ---------
Cash flows from investing activities
Capital expenditures (321) (372)(670) (740)
Proceeds from the sale of assets 1 1,014
Other-net 81 17(11) -
--------- ---------
Net cash used by investing activities (240) (355)(680) 274
--------- ---------
Cash flows from financing activities
Net borrowings (repayments) under credit facilities (547) 161(482) (767)
Long-term debt matured, redeemed, or repurchased (201) (283)(346) (491)
Long-term debt issued 54 -
Common stock issued 10 2022 32
Common stock repurchased - (503)
Dividends paid (108) (115)(217) (225)
Other-net 3 9- 23
--------- ---------
Net cash used by financing activities (843) (711)(969) (1,931)
--------- ---------
Net change in cash and cash equivalents (21) (41)26 (2)
Cash and cash equivalents at January 1 281 286
--------- ---------
Cash and cash equivalents at March 31June 30 $ 260307 $ 245284
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 117344 $ 148385
Income taxes(net of refunds) $ 323 $ (2)87
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of
this statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONDENSED CONSOLIDATED INCOME STATEMENT (in millions)
Three months ended March 31,June 30, Six months ended June 30,
2000 1999 --------- ---------2000 1999
-------- -------- -------- --------
Operating revenues
Electric utility $ 1,6011,801 $ 1,5331,828 $ 3,402 $ 3,361
Gas utility 617 552495 405 1,112 957
-------- -------- -------- --------
Total operating revenues 2,218 2,0852,296 2,233 4,514 4,318
Operating expenses
Cost of electric energy 513 409975 526 1,488 935
Cost of gas 283 246182 138 465 384
Operating and maintenance, net 551 626543 608 1,094 1,234
Depreciation, amortization, and decommissioning 301 38244 509 345 891
-------- -------- -------- --------
Total operating expenses 1,648 1,6631,744 1,781 3,392 3,444
-------- -------- -------- --------
Operating income 570 422552 452 1,122 874
Interest expense, net 141 154144 148 285 302
Other income, net 512 11 17 22
-------- -------- -------- --------
Income before income taxes 434 279420 315 854 594
Income taxes 200 126198 137 398 263
-------- -------- -------- --------
Net income 234 153222 178 456 331
Preferred dividend requirement 6 6 12 12
-------- -------- -------- --------
Income available for common stock $ 228216 $ 147172 $ 444 $ 319
======== ======== ======== ========
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of
this statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
March 31,---------------------------
June 30, December 31,
2000 1999
------------ -----------
ASSETS
Current assets
Cash and cash equivalents $ 8784 $ 80
Short-term investments 2327 21
Accounts receivable, net 1,1261,256 1,210
Inventories 249279 294
Prepayments 3234 34
Deferred income taxes 10982 119
--------- ---------
Total current assets 1,6261,762 1,758
Property, plant, and equipment
Electric 15,84016,002 15,762
Gas 7,3457,452 7,239
Construction work in progress 217208 214
--------- ---------
Total property, plant, and equipment (at original cost) 23,40223,662 23,215
Accumulated depreciation and decommissioning (10,756)(10,879) (10,497)
--------- ---------
Net property,Property, plant, and equipment, 12,646net 12,783 12,718
Other noncurrent assets
Regulatory assets 4,8795,273 4,895
Nuclear decommissioning funds 1,3001,336 1,264
Other 906970 835
-------- --------
Total noncurrent assets 7,0857,579 6,994
-------- --------
TOTAL ASSETS $ 21,35722,124 $ 21,470
======== ========
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of
this statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
March 31,---------------------------
June 30, December 31,
2000 1999
------------ -----------
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 209480 $ 449
Current portion of long-term debt 549398 465
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 4681,159 577
Related parties 2333 216
Regulatory balancing accounts 638574 384
Other 323292 333
Accrued taxes 344217 118
Other 516558 529
-------- -------
Total current liabilities 3,3604,001 3,361
Noncurrent liabilities
Long-term debt 4,7674,866 4,877
Rate reduction bonds 1,9551,890 2,031
Deferred income taxes 2,4712,662 2,510
Deferred tax credits 221212 231
Other 2,2692,354 2,252
------- -------
Total noncurrent liabilities 11,68311,984 11,901
Preferred stock with mandatory redemption provisions
6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137
Company obligated mandatorily redeemable preferred securities of
trust holding solely utility subordinated debentures
7.90%, 12,000,000 shares due 2025 300 300
Stockholders' equity
Preferred stock without mandatory redemption provisions
Nonredeemable - 5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable - 4.36% to 7.04%, outstanding 5,973,456 shares 142 149
Common stock, $5 par value, authorized 800,000,000 shares,
issued 321,314,760 shares 1,606 1,606
Common stock held by subsidiary, at cost, 19,481,213 and 7,627,765
shares, (200)respectively (475) (200)
Additional paid in capital 1,9711,972 1,964
Reinvested earnings 2,2132,312 2,107
-------- --------
Total stockholders' equity 5,8775,702 5,771
Commitments and contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 21,35722,124 $ 21,470
======== ========
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of
this statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONDENSED CONSOLIDATED CASH FLOWS (in millions)
For the threesix months ended March 31,June 30,
2000 1999
----------- -----------
Cash flows from operating activities
Net income $ 234456 $ 153331
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization, and decommissioning 301 382345 891
Deferred income taxes and tax credits-net (48) (194)170 (669)
Other deferred charges and noncurrent liabilities (52) (4)(303) (189)
Net effect of changes in operating assets and liabilities:
Short-term investments (2)(6) (1)
Accounts receivable 84 263(46) 239
Regulatory balancing accounts payable 254 212190 606
Inventories and prepayments 47 5415 12
Accounts payable - trade (302) (179)399 (192)
Accrued taxes 226 29199 583
Other working capital (24) 117(16) (71)
Other-net (30) (2)(5) 27
--------- ---------
Net cash provided by operating activities 688 1,0921,298 1,567
--------- ---------
Cash flows from investing activities
Capital expenditures (265) (304)(572) (600)
Proceeds from sale of assets - 1,014
Other-net 54 18(16) -
--------- ---------
Net cash used by investing activities (211) (286)(588) 414
--------- ---------
Cash flows from financing activities
Net borrowings (repayments) under credit facilities (240) 25831 (668)
Long-term debt matured, redeemed, or repurchased (102) (233)(216) (369)
Common stock repurchased -(275) (725)
Dividends paid (122) (106)(250) (208)
Other-net (6) -4 1
--------- ---------
Net cash used by financing activities (470) (806)(706) (1,969)
--------- ---------
Net change in cash and cash equivalents 7 -4 12
Cash and cash equivalents at January 1 80 73
--------- ---------
Cash and cash equivalents at March 31June 30 $ 8784 $ 7385
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 75261 $ 91282
Income taxes (net of refunds) $ - $ (3)226
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of
this statement.
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: GENERAL
Basis of Presentation
- ---------------------
This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation
and Pacific Gas and Electric Company (the Utility), a regulated subsidiary of
PG&E Corporation. The Notes to Condensed Consolidated Financial Statements
apply to both PG&E Corporation and the Utility. PG&E Corporation's condensed
consolidated financial statements include the accounts of PG&E Corporation and
its wholly owned and controlled subsidiaries, including the Utility
(collectively, the Corporation). The Utility's condensed consolidated
financial statements include its accounts as well as those of its wholly owned
and controlled subsidiaries.
The Utility's financial position and results of operations are the
principal factors affecting the Corporation's consolidated financial position
and results of operations. This quarterly report should be read in
conjunction with the Corporation's and the Utility's Condensed Consolidated
Financial Statements and Notes to Condensed Consolidated Financial Statements
incorporated by reference in their combined 1999 Annual Report on Form 10-K,
and the Corporation's and the Utility's other reports filed with the
Securities and Exchange Commission since their 1999 Form 10-K was filed.
PG&E Corporation and the Utility believe that the accompanying condensed
consolidated statements reflect all adjustments that are necessary to present
a fair statement of the condensed consolidated financial position and results
of operations for the interim periods. All material adjustments are of a
normal recurring nature unless otherwise disclosed in this Form 10-Q. All
significant intercompany transactions have been eliminated from the condensed
consolidated financial statements.
Certain amounts in the prior year's condensed consolidated financial
statements have been reclassified to conform to the 2000 presentation.
Results of operations for interim periods are not necessarily indicative of
results to be expected for a full year.
Effective January 1, 1999, PG&E Corporation changed its method of
accounting for major maintenance and overhauls at the PG&E National Energy Group.
Beginning January 1, 1999, the cost of major maintenance and overhauls,
principally at the PG&E Generating Company (PG&E Gen) business
segment,, have been accounted for as
incurred. Previously, the estimated cost of major maintenance and overhauls
was accrued in advance in a systematic and rational manner over the period
between major maintenance and overhauls. The change resulted in PG&E
Corporation recording income of $12 million net of income tax ($0.03 per share),of $8 million,
reflecting the cumulative effect of the change in accounting principle. The effect on 1999 results of operations was
immaterial. The
Utility consistently has accounted for major maintenance and overhauls as
incurred.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions. These estimates and assumptions
affect the reported amounts of revenues, expenses, assets, and liabilities and
the disclosure of contingencies. Actual results could differ from these
estimates.
NOTE 2: THE CALIFORNIA ELECTRIC INDUSTRY
In 1998, California became one of the first states in the country to
implement electric industry restructuring and establish a competitive market
framework for electric generation. Today, most Californians may continue to
purchase their electricity from investor-owned utilities such as Pacific Gas
and Electric Company, or they may choose to purchase electricity from
alternative generation providers (such as unregulatedindependent power generators and
unregulated
retail electricity suppliers such as marketers, brokers, and aggregators).
For those customers who have not chosen an alternative generation provider,
investor-owned utilities, such as the Utility, continue to be the generation
providers. Investor-owned utilities continue to provide distribution services
to substantially all customers within their service territories, including
customers who choose an alternative generation provider.
Competitive Market Framework
- ----------------------------
An Independent System Operator (ISO) and Power Exchange (PX) operate in
California to facilitate competition. The PX provides a competitive auction
process to establish market clearingmarket-clearing prices for electricity in the markets
operated by the PX. The ISO schedules delivery of electricity for all market
participants.participants and operates the real time and ancillary services markets for
electricity. (Ancillary services are needed to maintain the reliability of
the electric grid.) The Utility continues to own and maintain a portion of theits
transmission system, but the ISO controls the operation of the system. Unless
or untilDuring
the California Public Utilities Commission (CPUC) determines
otherwise,transition period, the Utility is required to bid or schedule into the PX
and ISO markets all of the electricity generated by its power plants and
electricity acquired under contractual agreements with unregulated generators.
Also,Until at least May 31, 2001, the Utility is required to buy frominvestor owned utilities must procure all the PX all
electricity needed to provide
service tofor retail customers that(i.e. those customers who continue to
choose the Utilityinvestor-owned utilities as their electricity supplier, unlesssupplier) from the CPUC decides otherwise.PX
and ISO real time markets at prevailing market prices. Beginning June 1,
2001, it is possible that California's investor owned utilities may be
permitted to begin purchasing electricity for their retail customers from any
other exchange that meets conditions established by the California Public
Utilities Commission (CPUC) (qualified exchanges). At the conclusion of the
transition period or March 31, 2002, whichever is earlier, the mandatory buy
requirements cease and the investor owned utilities may purchase electricity
for their retail customers from any and all sources.
In November 1999,June 2000, the ISO lowered the price limitation on ancillary services
and electricity purchased in the real time energy market that it purchases
from market participants to $500 from $750 per megawatt hour (MWh). Effective
August 7, 2000, the ISO further lowered the price limitation to $250 per MWh.
The new price limitation will remain in effect until October 15, 2000, when
the ISO must reapply to the Federal Energy Regulatory Commission (FERC) approved
thefor
an extension of the ISO's authority to establish price limitations through
2000.limitations. The ISO
Board increasedcharges the applicableUtility and other market participants for providing ancillary
services and real time energy purchases. Although the PX energy market has no
price limitations, the ISO price limitation becomes a de facto limitation on
the PX day ahead market where bids to $750 per
megawatt-hour (MWh) on October 1, 1999, but has the optionpurchase electricity and bids to decrease it to
$500 per MWh or make other changes, in view of the FERC's decision. This
limits the amount of volatility that occurs in the Californiasell
electricity
market. However, the ISO will review the appropriate level for any price
limitations for the summernext day are matched.
High PX prices in June and July 2000 have caused certain regulators,
legislators and consumer advocates to express concern over the impact of
2000higher electric prices on customers after the transition period. Certain of
these regulators and legislators have suggested that regulatory intervention
may be necessary to mitigate the higher power prices in light of market redesign efforts now
being considered, including changes to reduce uninstructed deviations from ISO
dispatch orders and changes to permit loads, to participate by submitting bids
for price responsive demand in energy or ancillary services markets.California.
For the quartersthree and six months ended March 31,June 30, 2000 and 1999, the cost of
electric energy for the Utility, reflected on the Statement ofCondensed Consolidated
Income Statement, is comprised of the cost of fuel for electric generation and
qualifying facility (QF) purchases, the cost of PX purchases, ancillary
services purchased fromcharged by the ISO, cost of transmission, and the cost of Utility generation, net of sales to the PX, as follows:
March 31, March 31,
2000 1999
------------ -----------
Three months ended June 30, Six months ended June 30,
2000 1999 2000 1999
-------- -------- -------- --------
(in millions)
Cost of fuel for electric generation and
QF purchases $ 382 $ 398 $ 611 $ 768
Cost of purchases from the PX 489 174 685 326
Cost of ancillary services 472 111 675 221
Proceeds from sales to the PX (368) (157) (483) (380)
-------- -------- -------- --------
Total Utility cost of electric energy $ 975 $ 526 $ 1,488 $ 935
======== ======== ======== ========
Recovery of fuel for electric generationthese costs and qualifying facilities (QF) purchases $ 229 $ 371
Costuse of purchases fromproceeds during the PX 196 152
Cost of ancillary services 203 110
Proceeds from sales to the PX (115) (224)
------------ -----------
$ 513 $ 409
============ ===========transition period is
discussed below.
Transition Period, Rate Freeze, and Rate Reduction
- --------------------------------------------------
California's electric industry restructuring established a transition
period during which electric rates remain frozen at 1996 levels (with the
exception that, on January 1, 1998, rates for small commercial and residential
customers were reduced by 10 percent and remain frozen at this reduced level)
and investor-owned utilities may recover their transition costs. Transition
costs are generation-related costs that prove to be uneconomic under the new
competitive structure. The transition period ends the earlier of December 31,
2001, or when the particular utility has recovered its eligible transition
costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public purpose
programs, nuclear decommissioning, and rate reduction bond debt service. To
the extent the revenues from frozen rates exceed authorized Utility costs, the
remaining revenues constitute the competition transition charge (CTC), which
recovers the transition costs. These CTC revenues are being recovered from
all Utility distribution customers and are subject to seasonal fluctuations in
the Utility's sales volumes and certain other factors. As the CTC is
collected regardless of the customer's choice of electricity supplier (i.e.,
the CTC is non-bypassable), the Utility believes that the availability of
choice to its customers will not have a material impact on its ability to
recover transition
costs.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion (the expected revenue reduction from the rate decrease) of its
transition costs with the proceeds from the rate reduction bonds. The bonds
allow for the rate reduction by lowering the carrying cost on a portion of the
transition costs and by deferring recovery of a portion of these transition
costs until after the transition period. During the rate freeze, the rate
reduction bond debt service will not increase the Utility customers' electric
rates. If the transition period ends before December 31, 2001, the Utility may
be obligated to return a portion of the economic benefits of the transaction
to customers. The timing of any such return and the exact amount of such
portion, if any, have not yet been determined.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public purpose
programs, nuclear decommissioning, rate reduction bond debt service, and the
cost of procuring electricity for the Utility's retail customers. To the
extent the revenues from frozen rates exceed authorized Utility costs, the
remaining revenues constitute the competition transition charge (CTC), which
recovers the transition costs. These CTC revenues are being recovered from all
Utility distribution customers and are subject to seasonal fluctuations in the
Utility's sales volumes, fluctuating PX energy prices, and certain other
factors. The CTC is collected regardless of the customer's choice of
electricity supplier (i.e., the CTC is non-bypassable).
Authorized Utility costs in excess of revenues from frozen rates increase
the amount of costs deferred for future recovery. The deferred costs are
recoverable during the transition period when and if revenues from frozen
rates exceed authorized Utility costs. The recovery of these deferred costs
reduce or eliminate the amount of revenues from frozen rates available for
recovery of transition costs. During the month of June 2000, the Utility's
current costs exceeded revenues provided by frozen rates by approximately $700
million, primarily as a result of high electric procurement prices. If the
Utility were unable to defer these costs, the Utility's earnings would be
reduced accordingly.
Transition Cost Recovery
- ------------------------
Although most transition costs must be recovered during the transition
period, certain transition costs can be recovered after the transition period.
Except for certain transition costs discussed below, at the conclusion of the
transition period, the Utility will be at risk to recover any of its remaining
generation costs through market-based revenues.
Transition costs consist of (1) above-market sunk costs (costs associated
with utility generating facilities that are fixed and unavoidable and that
were included in customers' rates on December 20, 1995) and future sunk costs,
such as costs related to plant removal, (2) costs associated with long-term
contracts to purchase power at above-market prices from qualifying facilities
and other power suppliers, and (3) generation-related regulatory assets and
obligations. (In general, regulatory assets are expenses deferred in the
current or prior periods, to be included in rates in subsequent periods.)
Above-market sunk costs result when the book value of a facility exceeds
its market value. Conversely, below-market sunk costs result when the market
value of a facility exceeds its book value. The total amount of generation
facility costs to be included as transition costs is based on the aggregate of
above-market and below-market values. The above-market portion of these costs
is eligible for recovery as a transition cost. The below-market portion of
these costs will reduce other unrecovered transition costs. These above-Revenues
generated from the Utility's sales to the PX and below-market sunkISO that exceed authorized
costs are relatedalso used to generating facilities that are
classified as either non-nuclear or nuclear sunkoffset transition costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until the valuation of
the Utility's remaining non-nuclear generating assets, primarily its
hydroelectric generating assets, is completed. The valuation, through
appraisal, sale, or other divestiture, must be completed by December 31, 2001.
The value of seven of the Utility's other non-nuclear generating facilities
was determined when these facilities were sold to third parties. The portion
of the sales proceeds that exceeded the book value of these facilities was
used to reduce other transition costs. On September 30, 1999, the Utility
filed an application with the CPUC to determine the market value of its
hydroelectric generating facilities and related assets through an open,
competitive auction. (See "Generation Divestiture" below.) TheProvided an
alternative means of valuing the hydroelectric facilities is not used, the
Utility proposes to use an auction process similar to the one previously
approved by the CPUC and successfully used in the sale of the Utility's fossil
and geothermal plants. If the market value of the Utility's hydroelectric
facilities is determined based upon any method other than a sale of the
facilities to a third party, a material charge to Utility earnings could
result. Any excess of market value over book value would be used to reduce
other transition costs. (See "Generation Divestiture" below.)
For nuclear transition costs, revenues provided for transition cost
recovery are based on the accelerated recovery of the investment in Diablo
Canyon Nuclear Power Plant (Diablo Canyon) over a five-year period ending
December 31, 2001. The amount of nuclear generation sunk costs was determined
separately through a CPUC proceeding and was subject to a final verification
audit that was completed in August 1998. The audit of the Utility's Diablo
Canyon accounts at December 31, 1996, resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. The independent accounting firm also issued an agreed-upon special
procedures report, requested by the CPUC, that questioned $200 million of the
$3.3 billion sunk costs. The CPUC will review the results of the audit and
may seek to make adjustments to Diablo Canyon's sunk costs subject to
transition cost recovery. In May 2000, the Utility filed a petition at the
CPUC to close out the audit report without any changes in rates. The petition
is not opposed by the two consumer advocacy groups who originally requested
the audit, the Commission'sCPUC's Office of Ratepayer Advocates (ORA) and The Utility
Reform Network (TURN). At this time, the Utility cannot predict what actions,
if any, the CPUC may take regarding the audit report.
Costs associated with the Utility's long-term contracts to purchase
electric power are included as transition costs. Regulation required the
Utility to enter into such long-term agreements with non-utility generators.
generators to
purchase electric power at fixed prices. Prices fixed under these contracts
are now typicallyhave generally been above prices for power in wholesale markets. Over the
remaining life of these contracts, the Utility estimates that it will purchase
299 million MWh of electric power. The contracts expire at various dates
through 2028. To the extent that the individual contract prices are above the
market price, the Utility is collecting the difference between the contract
price and the market price from customers, as a transition cost, over the term
of the contract. The contracts expire at various dates through 2028.To the extent that the contracted prices are below the
market price, the Utility is using the savings to offset other transition
costs during the transition period.
The total costs under long-term contracts are based on several variables,
including the capacity factors of the related generating facilities and future
market prices for electricity. For the threesix months ended March 31,June 30, 2000 and
1999, the average price paid under the Utility's long-term contracts for
electricity was 5.36.2 cents and 5.56.1 cents per kilowatt-hour (kWh), respectively.
The average costunconstrained price for base load electric energy (the price
received for a constant level of electricity purchasedelectric generation for all hours of electric
demand) sold at market rates frominto the California PX day-ahead market for the
threesix months ended March 31,June 30, 2000 and 1999, was 3.6 cents4.7cents and 2.32.2 cents per kWh,
respectively.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At March 31,June 30, 2000 and December 31, 1999, the Utility's net generation-related net
regulatory assets, which include uncollected electric procurement costs
(discussed below), totaled $4.4 billion and $4.0 billion.billion, respectively. These
regulatory assets increased by $439 million for the six months ended June 30,
2000, and decreased $813 million for the six months ended June 30, 1999.
Certain transition costs can be recovered through a non-bypassable charge
to distribution customers after the transition period. These costs include
(1) certain employee-related transition costs, (2) above-market payments under
existing long-term contracts to purchase power, discussed above, (3) up to $95
million of transition costs to the extent that the recovery of such costs
during the transition period was displaced by the recovery of electric
industry restructuring implementation costs, and (4) transition costs financed
by the rate reduction bonds. Transition costs financed by the issuance of rate
reduction bonds will be recovered over the term of the bonds. In addition,
the Utility's nuclear decommissioning costs are being recovered through a
CPUC-authorized charge, which will extend until sufficient funds exist to
decommission the nuclear facility. During the rate freeze, the charge for
these costs will not increase Utility customers' electric rates. Excluding
these exceptions, the Utility will write off any transition costs not
recovered during the transition period.
The Utility is amortizing its transition costs, including most generation-
related regulatory assets, over the transition period in conjunction with the
available CTC revenues. During the transition period, a reduced rate of
return on common equity of 6.77 percent applies to all generation assets,
including those generation assets reclassified to regulatory assets.
Effective January 1, 1998, the Utility started collecting these eligible
transition costs through the non-bypassable CTC, generation divestiture, and
generation divestiture.
Regulatory assets related to electric industry restructuring increased by $15
million for the quarter ended March 31, 2000, and decreased $247 million for
the quarter ended March 31, 1999.other credits.
During the transition period, the CPUC reviews the Utility's compliance
with accounting methods established in the CPUC's decisions governing
transition cost recovery and the amount of transition costs requested for
recovery. In February 2000, the CPUC approved substantially all non-nuclear
transition costs that were amortized during the first six months of 1998. The
CPUC currently is currently reviewing non-nuclear transition costs amortized from July
1, 1998, to June 30, 1999.
Generation Divestiture
- ----------------------
In 1998, the Utility sold three fossil-fueled generation plants for $501
million. These three fossil-fueled plants had a combined book value at the
time of the sale of $346 million and had a combined capacity of 2,645 megawatts
(MW).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled
plants had a combined book value of $256 million and had a combined capacity of
3,065 MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
The gains from the sale of the fossil-fueled generation plants were used to
offset other transition costs. Likewise, the loss from the sale of the
complex of geothermal generation facilities is being recovered as a transition
cost.
The Utility has retained a liability for required environmental remediation
related to any pre-closing soil or groundwater contamination at the plants it
has sold.
On September 30, 1999, the Utility filed anThe Utility's application with the CPUC to determine the market value of its
hydroelectric generating facilities and related assets through an open,
competitive auction. The Utility proposes to
use an auction process similaris currently pending at the CPUC. According to the one previously approved by the CPUC and
successfully usedCPUC's
revised procedural schedule, a draft environmental impact report is expected
to be published for public comment in the sale of the Utility's fossil and geothermal plants.
Under the process proposed in the application, the PG&E National Energy Group
would be permitted to participate in the auction on the same basis as other
bidders.
The sale of the hydroelectric facilities would be subject to certain
conditions, including the transfer or re-issuance of various permits and
licenses by the FERC and other agencies. In addition, the FERC must approve
assignment of the Utility's Reliability Must Run Contract with the ISO for any
facility subject to such contract. Under the proposed purchase and sale
agreement, the CPUC's approval of the proposed sale on terms acceptable to the
Utility in the Utility's sole discretion is also a condition precedent to the
closing of any sale.
The CPUC has ordered that the proceeding be divided into two concurrent
phases: one to review the potential environmental impacts of the proposed
auction under the California Environmental Quality ActSeptember 2000 and a second to
determine whether the Utility's auction proposal, or some other alternative to
the proposal, is in the public interest. The ruling sets a procedural
schedule that calls for a final CPUC decision
on the Utility's auction proposal by
October 19, 2000, and a final environmental impact report publishedis now expected in NovemberDecember 2000. The
ruling alsoschedule calls for the auction, if approved, to begin in mid-December. The
schedule anticipates that a final CPUC decision approving the sale would be
issued within 210 days from the adoption of the CPUC decision authorizing the
auction (i.e., by May 15, 2001. Finally, the ruling
prohibitsend of July 2001) and the divestiture process would be
closed within two weeks thereafter. The Utility and several other parties to
the proceeding, including TURN, the Agricultural Energy Consumers Association
(AECA), and the Coalition of California Utility Employees (CUE), have been
engaged in settlement discussions regarding the valuation and disposition of
the Utility's hydroelectric generating assets. The possible settlement being
discussed centers around a framework that includes the transfer of the
hydroelectric facilities at an agreed-upon value to a non-utility affiliate of
the Utility. Under this framework, the affiliate would hold and operate the
assets, subject to a revenue sharing contract between the affiliate and the
Utility that would permit the affiliate to recover an authorized inflation-
indexed operations and maintenance allowance, as well as a reasonable return
on capital investment. If revenue from withdrawing its application without expressthe hydroelectric facilities exceeds
the authorized costs, 90 percent of the excess revenue would be transferred to
the Utility and refunded to ratepayers. If the revenues fall short of the
authorized revenue requirement, 90 percent of any shortfalls would be billed
to the Utility by the affiliate and recovered from ratepayers.
Any settlement that may eventually be reached between any parties must be
submitted to the CPUC authority.for approval. Under the CPUC's rules, a settlement
proposal in this proceeding must be filed no later than August 14, 2000. It
is uncertain whether the CPUCexpected that a settlement proposal will ultimately approve the
Utility's auction proposal.
On February 17, 2000, the CPUC issued a decision in another proceeding, the
1998 Annual Transition Cost Proceeding (ATCP), that requires California
investor-owned utilities to estimate the market value of their remaining non-
nuclear generating assets, including the land associated with those assets, at
a value not less than the net book value of those assets on an aggregate basis
and to credit the Transition Cost Balancing Account (TCBA) with the estimated
value. The decision encourages the utilities to base such estimates on
realistic assessments of the market value of the assets. The decision
provides that if the estimated market valuation is less than book value for
any individual asset, accelerated amortization of the associated transition
costs will continue until final market valuation of the asset occurs through
sale, appraisal, or other divestiture. If the final value of the assets,
determined through sale, appraisal, or other divestiture, is higher than the
estimate, the excess amount would be used to reduce remaining transition
costs, if any. The utilities are required to file the adjusted entries to
their respective TCBA based on the estimated market valuesfiled with the CPUC by
May 31, 2000.for
approval before that date. The filing will become effective after appropriate review byCPUC may accept the CPUC's Energy Division and will be subjectproposed settlement or
reject it, suggest changes to review in the next ATCP. On
May 2, 2000,it, or adopt a proposed decision was issued recommending the establishment of
an accounting mechanism to permit a regulatory asset to be recorded equal to
the amount credited to the TCBA. If an estimate of the market value of the
non-nuclear generating assets is adopted that exceeds the aggregate net book
value of those assets, and if an appropriate accounting mechanism is not
adopted, a charge to earnings would result.different valuation approach.
At March 31,June 30, 2000, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.7 billion, excluding
approximately $0.5$0.4 billion of net investment reclassified as regulatory
assets. Any excess of market value over the $0.7 billion book value would be
used to reduce transition costs, including the remaining $0.5$0.4 billion of
regulatory assets related to the hydroelectric generation assets. If the
market value of the hydroelectric generation assets is determined by any
method other than a sale of the assets to aan unrelated third party, or if the winning
bidder for any of the auctioned assets is the PG&E National Energy Group, a material
charge to Utility earnings could result. The timing and nature of any such
charge is dependent upon the valuation method and procedure adopted, and the
method of implementation. As discussed above, it is possible that the
CPUC will require an interim valuation through an estimate of market value of
the assets prior to transfer, sale or other divestiture, which could also
result in a material charge. While transfer or sale to an affiliated entity such
as the PG&E National Energy Group would result in a material charge to income,
neither PG&E Corporation nor the Utility believes that the sale of any
generation facilities to a third party will have a material impact on its
results of operations.
The Utility's ability to continue recovering its transitionnet generation-related
regulatory assets, which includes deferred electric procurement costs, depends
on several factors, including (1) the continued applicationfederal and state regulatory
implementation of the regulatory framework established by the CPUC and state legislation,
(2) the amount of transition costs ultimately approved for recovery by the
CPUC, (3) the determined value of the Utility's hydroelectric generation
facilities, (4) future Utility sales levels, (5) future Utility fuel and operating
costs, and (6) the market price of electricity.electricity procured from and sold to the
PX and ISO. During the second quarter PX energy prices increased
substantially, reducing the amount of revenues from frozen rates available to
recover transition costs. Many factors influence the PX energy market,
including weather, availability of hydro-electric generation resources,
demand, gas prices, and the availability of generation resources. If the
prices experienced by the Utility in June were to prevail throughout the
remainder of the transition period, the Utility would be unable to recover all
of the net generation-related regulatory assets, including its deferred
electric procurement costs by the end of the transition period. Given theits
current evaluation of all these factors, PG&E Corporation believes that the
Utility will recover its
transitionthese regulatory assets including uncollected electric
procurement costs. However, a changechanges in one or more of these factors could
affect the probability of recovery of transition coststhese regulatory assets and result in a
material charge.
Post-Transition Period
- ----------------------
The timing of the end of the rate freeze and corresponding transition
period will, in part, depend on the timing of the valuation of the Utility's
hydroelectric generating assets and the ultimate determined value of such
assets since any excess of market value over the assets' book value would be
used to reduce transition costs. If the value of the Utility's hydroelectric
generation assets is significantly higher than the related book value, the
transition period and the rate freeze could end before December 31, 2001,2001.
The CPUC has issued a decision which requires the Utility to refund to
electric customers any over-collected transition costs (plus interest at the
Utility's three-month commercial paper rate) within one year after the end of
the rate freeze. The decision also prohibits the Utility from collecting
after the rate freeze certain electric costs incurred during the rate freeze
but not recovered during the rate freeze, including under-collected accounting
balances relating to power purchases, such as power purchased from the PX. At
June 30, 2000, the aggregate balance of these accounts was approximately $700
million. The CPUC decision prohibits offsetting these specific accounts
against over-collected transition costs. The Utility has appealed this
decision in the California Court of Appeals and potentially could end during 2000.a decision is pending.
The CPUC also has established the Purchased Electric Commodity Account
(PECA) for the Utility to track energy costs after the rate freeze and
transition period end. In October 1999,June 2000, the CPUC issued a decision in the second
phase of the Utility's post-
transitionpost-transition period electric ratemaking proceeding.
Among other matters,things, the CPUC'sCPUC determined that the PECA would reflect a pass-
through of energy costs, possibly subject to after-the-fact reasonableness
reviews. The decision addressesdetermines that after the mechanisms for ending the currentrate freeze ends there will be
two electric rate freeze
and for establishing post-transition period accounting mechanismsproceedings which will, among other things, address electric
energy procurement practices and rates.
The decision prohibitsAfter the Utility from continuing to price electric
generation fromrate freeze ends Diablo Canyon based onwill be operated as a competitive
generator of electricity with revenues generated from prevailing market rates.
During the rate freeze Diablo Canyon's operating costs have been recovered as
a non-transition cost through the incremental cost incentive price (ICIP) after the transition period has ended..
The ICIP, which has been in place since January 1, 1997, is a performance-basedperformance-
based mechanism that establishes a rate per kilowatt-hour (kWh) generated by
the facility. The ICIP prices for 1999, 2000, and 2001 are 3.37 cents per
kWh, 3.43 cents per kWh, and 3.49 cents per kWh, respectively. The average
price for base load electric energy
(the price received for a constant level of electric generation for all hours
of electric demand) sold at market rates to the California PX for the three-
month periods ended March 31, 2000 and 1999, was 3.6 cents and 2.3 cents per
kWh, respectively. The averageunconstrained price for base load electric energy sold at market rates tointo
the California PX day-ahead market for the 12 months ending March 31,six-month periods ended June 30,
2000 and 1999, was 4.04.7 cents and 2.2 cents per kWh. Future market prices may be higher or lower. Under the
CPUC's decision, after the transition period, the Utility must price Diablo
Canyon generation at the prevailing market price for power.
ThekWh, respectively.
As required by a prior CPUC decision requires the Utility to provide quarterly forecasts of
when the Utility's rate freeze (i.e., transition period) may end based on various assumptions regarding energy prices and the market value of the
Utility's remaining generation assets. The Utility is required to notify the
CPUC three months before the earliest forecasted end of its rate freeze and
provide draft tariff language and sample calculations of the rates that would
go into effect when the rate freeze ends. After the Utility completes its
transition cost recovery, it must implement its post-rate-freeze rates.
After the rate freeze and transition periods end, the Utility must refund
to electric customers any over-collected transition costs (plus interest at
the Utility's three-month commercial paper rate) within one year after the end
of the rate freeze. The Utility also will be prohibited from collecting after
the rate freeze certain electric costs incurred during the rate freeze but not
recovered during the rate freeze, including costs that are not classified as
transition costs and are not related to generation assets such as under-
collected accounting balances relating to power purchases. Through the end of
its rate freeze, the Utility will continue to incur certain non-transition
costs and place those costs into balancing and memorandum accounts for future
recovery. There is a risk that the Utility will be unable to collect certain
non-transition costs that, due to lags in the regulatory cost approval
process, have not been approved for recovery nor collected when the rate
freeze ends. The Utility is unable to predict the amount of such potential
unrecoverable costs.
In November 1999,June 30, 2000, the Utility filed
an application with the CPUC requesting approval of its proposal for rehearingsharing
with ratepayers 50 percent of the CPUC's decision. In March 2000, the CPUC deniedpost-rate freeze net benefits of operating
Diablo Canyon in electricity markets. The net benefit sharing methodology
proposed in the Utility's application would be effective at the end of the
current electric rate freeze for rehearing on the issues of Diablo Canyon ICIPUtility's customers and post-transition period
recovery of non-transition costs. On April 17, 2000,would continue
for as long as the Utility filed a
petition for review inowned Diablo Canyon. Under the California Court of Appeal on the issue of post-
transition period recovery of non-transition costs.
The CPUC also has established the Purchased Electric Commodity Account
(PECA) for the Utility to track energy costs after the rate freeze and
transition period end. The CPUC intends to explore other ratemaking issues,
including whether dollar-for-dollar recovery of energy costs is appropriate,
in the second phase of the post-transition period electric ratemaking
proceeding. There are three primary options for the future regulatory
framework for utility electric energy procurement cost recovery after the rate
freeze: (1) a CPUC-defined procurement practice, that if followed byproposal, the
Utility would pass through costs without the need for reasonableness reviews,
(2) a pass-through of costs subject to after-the-fact reasonableness reviews,
or (3) a procurement incentive mechanism with rewards and penalties determined
based on the Utility's energy purchasing performance compared to a benchmark.
The Utility proposed adoption of either a defined procurement practice or a
procurement incentive mechanism, neither of which would involve reasonableness
reviews. On March 17, 2000, the CPUC issued a proposed decision that states
that after the rate freeze, there will be two electric rate proceedings to
address electric energy procurement practices and rates. The Revenue
Adjustment Proceeding (RAP) will be a forecast of costs, and the ATCP will
include a review of procurement costs to the extent costs above the wholesale
PX rate are included in the PECA. The volatility of earnings and risk
exposure of the Utility related to post-transition period purchases of
electricity is dependent on which of these options, or some other approach, is
adopted.
Further, pursuant to the 1997 CPUC decision establishing the ICIP, the
Utility is required to begin sharing 50 percent ofshare the net benefits of operating Diablo Canyon based on the
audited profits from operations, consistent with ratepayers at the endprior CPUC decision. If
Diablo Canyon experiences losses, such losses would be accrued and netted
against profits in the calculation of the transition period.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 Utility's sharing proposal is subject to comments by other parties and
possibly evidentiary hearings. The Utility is required to file an application by July 2000 with its proposalhas proposed that the CPUC adopt a
procedural schedule that calls for the methodsa final decision to be usedissued in the valuationfirst
quarter of 2001. The CPUC may decide to implement a different procedural
schedule than proposed by the benefits associated with
the operation of Diablo Canyon, and the mechanism to be used to share these
benefits with ratepayers.Utility. The Utility and PG&E Corporation are
unable to predict what type of valuation and sharing mechanism will be adopted
and what the ultimate financial impact of the sharing mechanism will have on
results of operations or financial position.
The ultimate financial impact of the post-transition period issues
discussed above will depend on the date the Utility's transition cost recovery
is completed andend of the rate freeze ends,will depend
upon future costs including Diablo Canyon
operating costs, futurePX and ISO market prices for electricity,during the method adopted by
the CPUC for sharing net benefits of operating Diablo Canyon with ratepayers,transition period, the amount
of any electric non-transition costs that have been incurred but not recovered
as of the end of the rate freeze, the timing of various regulatory proceedings
in which the Utility seeks approval for rate recovery of various costs incurred
during the rate freeze, and other variables that PG&E Corporation and the
Utility are unable to predict.
After the transition period, it is possible that the Utility's future earnings
from its electric distribution and transmission operations will be subject to
volatility due to sales fluctuations.
NOTE 3: RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
The following table is a summary of the contract or notional amounts and
maturities of PG&E Corporation's contracts used for non-hedging activities
related to commodity risk management as of March 31,June 30, 2000 and 1999. Short and
long positions pertaining to derivative contracts used for hedging activities
as of March 31,June 30, 2000 and 1999, are immaterial.
Maximum
Natural Gas, Electricity, Purchase Sale Term in
and Natural Gas Liquids Contracts (Long) (Short) Years
- ---------------------------------------------------------------------------
(billions of MMBtu equivalents (1))
Non-Hedging Activities - March 31,June 30, 2000
Swaps 1.74 1.66 72.13 2.04 6
Options 0.80 0.830.58 0.49 8
Futures 0.10 0.11 3
Forward Contracts 2.36 1.94 16
Non-Hedging Activities - June 30, 1999
Swaps 3.90 3.73 7
Options 1.14 0.96 5
Futures 0.29 0.34 2
Forward Contracts 2.22 13.00 11
Non-Hedging Activities - March 31, 1999
Swaps 3.83 3.65 8
Options 1.08 0.99 5
Futures 0.55 0.57 3
Forward Contracts 2.62 2.672.93 2.98 9
(1) One MMBtu is equal to one million British thermal units. PG&E
Corporation's electric power contracts, measured in megawatts, were converted
to MMBtu equivalents using a conversion factor of 10 MMBtu's per 1 megawatt-
hour. PG&E Corporation's natural gas liquids contracts were converted to
MMBtu equivalents using an appropriate conversion factor for each type of
natural gas liquids product.
Volumes shown for swaps represent notional volumes that are used to
calculate amounts due under the agreements and do not represent volumes
exchanged. Moreover, notional amounts are indicative only of the volume of
activity and are not a measure of market risk.
PG&E Corporation's net gains (losses) on swaps, options, futures, and
forward contracts held during the quartersthree and six months ended March 31,June 30, 2000 and
1999, are as follows:
March 31, March 31,
2000 1999
--------- ---------
(in millions)
Swaps $ (23) $ 235
Options 62 15
Futures 37 (9)
Forward contracts (31) (203)
------- -------
Net gain $ 45 $ 38
======= =======
Three months ended June 30, Six months ended June 30,
2000 1999 2000 1999
-------- -------- -------- --------
(in millions)
Swaps $ 90 $ (131) $ 79 $ 2
Options 24 (29) 62 (35)
Futures (42) 22 (24) (20)
Forward contracts (37) 131 (53) 95
-------- -------- -------- --------
Net gain (loss) $ 35 $ (7) $ 64 $ 42
======== ======== ======== ========
The following table discloses the estimated fair values of risk management
assets and liabilities as of March 31,June 30, 2000, and December 31, 1999. The ending
and average fair values and associated carrying amounts of derivative
contracts used for hedging purposes are not material as of March 31,June 30, 2000, and
December 31, 1999.
Average Ending
Fair Value Fair Value
- ---------------------------------------------------------------------------
(in millions)
Non-hedging activities - March 31,June 30, 2000
Assets
Swaps $ 146131 $ 48100
Options 90 87101 123
Futures 27 723 14
Forward Contracts 590 614804 1,261
------ ------
Total $1,059 $1,498
Noncurrent portion $ 499
Current portion $ 999
Liabilities
Swaps $ 107 $ 61
Options 52 34
Futures 37 33
Forward Contracts 760 1,276
------ ------
Total $ 853 $ 756956 $1,404
Noncurrent portion $ 322457
Current portion $ 434
Liabilities
Swaps $ 130 $ 42
Options 61 40
Futures 39 12
Forward Contracts 502 547
------ ------
Total $ 732 $ 641
Noncurrent portion $ 250
Current portion $ 391947
Non-hedging activities - December 31, 1999
Assets
Swaps $ 643 $ 244
Options 106 92
Futures 175 47
Forward Contracts 667 596
------ ------
Total $1,591 $ 979
Noncurrent portion $ 372
Current portion $ 607
Liabilities
Swaps $ 592 $ 218
Options 109 81
Futures 201 67
Forward Contracts 561 456
------ ------
Total $1,463 $ 822
Noncurrent portion $ 247
Current portion $ 575
PG&E Corporation, primarily through its subsidiaries, engages in risk
management activities for both non-hedging and hedging purposes. Non-hedging
activities are conducted principally through its unregulated subsidiary, PG&E
Energy Trading (PG&E ET). In compliance with regulatory requirements, the
Utility manages risk independently from the activities in PG&E Corporation's
unregulated businesses (see Note 1 for further discussion).businesses. The Utility primarily engages in hedging activities
which were immaterial for the threesix- month periods ended March 31,June 30, 2000 and 1999.
In valuing its electric power, natural gas, and natural gas liquids
portfolios, PG&E Corporation considers a number of market risks and estimated
costs and continuously monitors the valuation of identified risks and adjusts
them based on present market conditions. Considerable judgment is required to
develop the estimates of fair value; thus, the estimates provided herein are
not necessarily indicative of the amounts that PG&E Corporation could realize
in the current market.
Generally, exchange-traded futures contracts require deposit of margin
cash, the amount of which is subject to change based on market movement and in
accordance with exchange rules. Margin cash requirements for over-the-counter
financial instruments are specified by the particular instrument and often do
not require margin cash and are settled monthly. Both exchange-traded and
over-the-counter options contracts require payment/receipt of an option
premium at the inception of the contract. Margin cash for commodities futures
and cash on deposit with counterparties was $22$65 million at March 31,June 30, 2000.
The credit exposure of the five largest counterparties comprised
approximately $326$110 million of the total credit exposure associated with
financial instruments used to manage price risk. Counterparties considered to
be investment grade or higher comprise 8883 percent of the total credit
exposure.
NOTE 4: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST
HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES
The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust),
has outstanding 12 million shares of 7.90 percent cumulative quarterly income
preferred securities (QUIPS), with an aggregate liquidation value of $300
million. Concurrent with the issuance of the QUIPS, the Trust issued to the
Utility 371,135 shares of common securities with an aggregate liquidation
value of approximately $9 million. The only assets of the Trust are
deferrable interest subordinated debentures issued by the Utility with a face
value of approximately $309 million, an interest rate of 7.90 percent, and a
maturity date of 2025.
NOTE 5: DIVESTITURES
In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E Energy Services (PG&E ES), its wholly owned subsidiary,
through a sale. In December 1999, the intended disposal was accounted for as
a discontinued operation. In connection with this transaction, PG&E
Corporation's investment in PG&E ES was written down to its estimated net
realizable value. In addition, PG&E Corporation provided a reserve for
anticipated losses through the date of sale. The total provision for
discontinued operations was $58 million, net of income taxes of $36 million.
During the three-monthsix-month period ended March 31,June 30, 2000, $14.7$28.5 million after-tax was
charged against this reserve. On April 12,June 29, 2000, the PG&E National Energy Group
signed an agreement to sell specified assets, liabilities, and contractscompleted the sale of PG&E Energy Services Corporation. The consideration to be received by the PG&E National Energy Group isenergy commodities portfolio of its energy services
business for $20 million, plus net working capital of approximately $65
million, for a total of $85 million. The transaction is
expected to close by June 2000. The remaining componentsIn addition, the sale of PG&E Energy
Services Corporation, mainly the Value
Added Services business and various other assets will continue to be offeredwas completed on July 21,
2000, for sale. Theconsideration of $18 million. PG&E National Energy Group expects to complete this disposition prior to year-end 2000. The
dispositionis seeking
a buyer for the remainder of the assets formerly held by PG&E ES has been reflected in the financial statements as a
discontinued operation.ES. The PG&E
ES business segment generated net losses of $8$25 million (or $0.02$0.07 per share),
for the three monthsix-month period ended March 31,June 30, 1999.
The total assets and liabilities, including the charge noted above, of PG&E
ES included in the PG&E Corporation Consolidated Balance Sheet at March
31,June 30, 2000 and December 31, 1999 are as follows:
March 31,June 30, December 31,
2000 1999
----------- -----------
(in millions)
Assets
Current assets $ 8340 $ 114
Noncurrent assets 8853 83
----- -----
Total Assets 17193 197
Liabilities
Current liabilities 4020 61
Noncurrent liabilities 93 10
----- -----
Total Liabilities 4923 71
----- -----
Net Assets $ 12270 $ 126
===== =====
On January 27, 2000, the PG&E National Energy Group signed a definitive
agreement with El Paso Field Services Company (El Paso) providing for the
sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of
PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc.
(collectively, PG&E GT-Texas). The consideration to be received by the PG&E
National Energy Group includes $279 million in cash, subject to aadjustments
for working capital, adjustment,debt repayment, and certain other items, and includes
the assumption by El Paso of debt having value of $624
million, and other liabilities associated with PG&E GT-Texas.GT-Texas and
debt having a book value of approximately $570 million.
In 1999, PG&E Corporation recognized a charge against earnings of $890
million after-tax as follows: (1) an $819 million write downwrite-down of net
property, plant, and equipment, (2) the elimination of the unamortized
portion of goodwill, in the amount of $446 million, and (3) an accrual of $10
million representing selling costs.
Proceeds from the sale will be used to retire short-term debt associated
with PG&E GT-Texas' operations and for other corporate purposes. Closing of
the sale, which is expected in the first halfthird quarter of 2000, is subject to
approval under the Hart-Scott-Rodino Act.
The sale of PG&E GT-Texas represents disposal of the PG&E GTT business
segment and a portion of the PG&E ET business segment. PG&E GT-Texas' total
assets and liabilities, including the charge noted above, included in the
PG&E Corporation Condensed Consolidated Balance Sheet at March 31,June 30, 2000, and
December 31, 1999, are as follows:
March 31,June 30, December 31,
2000 1999
----------- -----------
(in millions)
Assets
Current assets $ 209279 $ 229
Noncurrent assets 974980 988
----- -----
Total Assets 1,1831,259 1,217
Liabilities
Current liabilities 458551 448
Noncurrent liabilities 578558 624
----- -----
Total Liabilities 1,0361,109 1,072
----- -----
Net Assets $ 147150 $ 145
===== =====
NOTE 6: COMMITMENTS AND CONTINGENCIES
Nuclear Insurance
- -----------------
The Utility has insurance coverage for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited (NEIL).
Under this insurance, if a nuclear generating facility suffers a loss due to a
prolonged accidental outage, the Utility may be subject to maximum
retrospective assessments of $15$13 million (property damage) and $4 million
(business interruption), in each case per policy period, in the event losses
exceed the resources of NEIL.
The Utility has purchased primary insurance of $200 million for public
liability claims resulting from a nuclear incident. The Utility has secondary
financial protection which provides an additional $9.3 billion in coverage,
which is mandated by federal legislation. It provides for loss sharing among
utilities owning nuclear generating facilities if a costly incident occurs.
If a nuclear incident results in claims in excess of $200 million, then the
Utility may be assessed up to $176 million per incident, with payments in each
year limited to a maximum of $20 million per incident.
Environmental RemediationMatters
- -------------------------
The Utility---------------------
Companies within the PG&E Corporation group may be required to pay for
environmental remediation at sites where it has been or may be a potentially
responsible party under the Comprehensive Environmental Response, Compensation
and Liability Act and similar state environmental laws. These sites include
former manufactured gas plant sites, power plant sites, and sites used by the Utility for the
storage or disposal of potentially hazardous materials. Under federal and
California laws, the Utility may be responsible for remediation of hazardous
substances, even if it did not deposit those substances on the site.
Utility:
The Utility records a liability when site assessments indicate remediation
is probable and a range of reasonably likely clean-up costs can be estimated.
The Utility reviews its remediation liability quarterly for each identified
site. The liability is an estimate of costs for site investigations,
remediation, operations and maintenance, monitoring, and site closure. The
remediation costs also reflect (1) current technology, (2) enacted laws and
regulations, (3) experience gained at similar sites, and (4) the probable
level of involvement and financial condition of other potentially responsible
parties. Unless there is a better estimate within this range of possible
costs, the Utility records the lower end of this range.
The cost of the hazardous substance remediation ultimately undertaken by
the Utility is
difficult to estimate. A change in estimate may occur in the near term due to
uncertainty concerning the Utility's responsibility, the complexity of environmental laws
and regulations, and the selection of compliance alternatives.
At March 31,June 30, 2000, the Utility expects to spend $303$300 million for hazardous
waste remediation costs at identified sites, including divested fossil-fueled
power plants. The Utility had an accrued liability of $275$272 million and $271
million at March 31,June 30, 2000 and December 31, 1999, respectively, representing the
discounted value of these costs.
Of the $275$272 million accrued liability discussed above, the Utility has
recovered $148 million through rates, including $34 million through
depreciation, and expects to recover another $99$96 million in future rates.
Additionally, the Utility is mitigating its costs by obtaining recovery of its
costs from insurance carriers and from other third parties as appropriate.
Environmental remediation at identified sites may be as much as $501$497
million if, among other things, other potentially responsible parties are not
financially able to contribute to these costs or further investigation
indicates that the extent of contamination or necessary remediation is greater
than anticipated. The Utility estimated this upper limit of the range of
costs using assumptions least favorable to the Utility, based upon a range of
reasonably possible outcomes. Costs may be higher if the Utility is found to
be responsible for clean-up costs at additional sites or outcomes change.
Further, as discussed in "Generation Divestiture" in Note 2, the Utility
will retain the pre-closing remediation liability associated with divested
generation facilities.
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 Commonwealth of Massachusetts is considering the adoption of more
stringent reductions in air emissions from electric generating facilities. In
addition, USGenNE has proposed an emission reduction plan that may include a
modernization of its 760 MW coal-fired power plant in Salem, Massachusetts.
The modernization, if undertaken, would use advanced technologies for
emissions removals. USGenNE is also studying various modernization
alternatives for its 1,586 MW coal-fired Brayton Point power plant in
Somerset, Massachussets.
On April 18, 2000, the Conservation Law Foundation (CLF) served various
PG&E Gen affiliates, including USGenNE, a notice of its intent to file suit
under the citizen suit provision of the Resource Conservation Recovery Act.
CLF stated in such notice that it plans in its suit to allege that the PG&E
Gen affiliates, generator of fossil fuel combustion wastes, has and is
contributing to the past and present handling, storage, treatment, and
disposal of such wastes at the Salem Harbor and Brayton Point power plants
which may present an imminent and substantial endangerment to health or the
environment. It further stated it will allege that PG&E Gen's management
practices in connection with such wastes has resulted in severe groundwater
contamination at both facilities. CLF has stated that it intends to seek an
order requiring all necessary measures be taken to halt what it characterizes
as the endangerment of health and environment. At this preliminary stage, we
are unable to determine whether the ultimate outcome of this matter would have
a material adverse effect on our results of operations or financial condition.
In May 2000, USGenNE received a request for information pursuant to Section
114 of the Clean Air Act from the U.S. Environmental Protection Agency ("EPA")
seeking detailed operating and maintenance history for the Salem Harbor and
Brayton Point power plants, which were acquired from NEES. We believe that
this request for information is part of EPA's industry-wide investigation of
coal-fired electric power generators to determine compliance with
environmental requirements under the Clean Air Act associated with repairs,
maintenance, modifications and operational changes made to coal-fired
facilities over the years. The EPA's focus is on whether there were physical
changes made in the past at the plants which were undertaken without first
receiving the required permits under the Clean Air Act. If the EPA were to
file an enforcement action in connection with this matter, then penalties may
be imposed and further emission reductions might be necessary at these plants.
PG&E Corporation believes the ultimate outcome of these matters will not have
a material impact on its or the Utility's financial position or results of operations.
Legal Matters
- -------------
Chromium Litigation:
Several civil suits are pending against the Utility in California state
court. The suits seek an unspecified amount of compensatory and punitive
damages for alleged personal injuries resulting from alleged exposure to
chromium in the vicinity of the Utility's gas compressor stations at Hinkley,
Kettleman, and Topock, California. Currently, there are claims pending on
behalf of approximately 9001,000 individuals.
The Utility is responding to the suits and asserting affirmative defenses.
The Utility will pursue appropriate legal defenses, including statute of
limitations or exclusivity of workers' compensation laws, and factual
defenses, including lack of exposure to chromium and the inability of chromium
to cause certain of the illnesses alleged.
PG&E Corporation believes that the ultimate outcome of these matters will
not have a material adverse impact on its or the Utility's financial position
or results of operations.
Texas Franchise Fee Litigation:
In connection with PG&E Corporation's acquisition of Valero Energy
Corporation, now known as PG&E Gas Transmission, Texas Corporation (PG&E GTT),
PG&E GTT succeeded to the litigation described below.
PG&E GTT and various of its affiliates are defendants in at least two class
action suits and five separate suits filed by various Texas cities.
Generally, these cities allege, among other things, that (1) owners or
operators of pipelines occupied city property and conducted pipeline
operations without the cities' consent and without compensating the cities,
and (2) the gas marketers failed to pay the cities for accessing and utilizing
the pipelines located in the cities to flow gas under city streets.
Plaintiffs also allege various other claims against the defendants for failure
to secure the cities' consent. Damages are not quantified.
In 1998, a jury trial was held in the separate suit brought by the City of
Edinburg (the City). This suit involved, among other things, a particular
franchise agreement entered into by a former subsidiary of PG&E GTT (now owned
by Southern Union Gas Company (SU)) and the City and certain conduct of the
defendants. On December 1, 1998, based on the jury verdict, the court entered
a judgment in the City's favor, and awarded damages of $5.3 million, and
attorneys' fees of up to $3.5 million plus interest. The court found that
various PG&E GTT and SU defendants were jointly and severally liable for $3.3
million of the damages and all the attorneys' fees. Certain PG&E GTT
subsidiaries were found solely liable for $1.4 million of the damages. The
court did not clearly indicate the extent to which the PG&E GTT defendants
could be found liable for the remaining damages. The PG&E GTT defendants are
in the process of appealing the judgment.
In connection with the certification of a class in one of the class actions, the court ordered notice to beopt-out notices were sent to allapproximately
159 Texas cities as potential class members and setting an opt-out deadline of December 31, 1997. Notices were mailed to
approximately 159 Texas cities. Fewerfewer than 20 cities opted out
by the deadline.deadline in 1997. In November 1999, the court signed an order dismissingdismissed from the class
42 cities because it determined there was no pipeline presence and no past or
present sales activity, leaving 106 cities in the class. A settlement
proposal has been presentedCertain of the 106
class members have elected to the court. On January 27, 2000, the court
approved the settlement proposal and established a 14-day period whether to
accept the negotiated settlement terms or opt out of the settlement. The Court
also stated that if Corpus Christi does not acceptsettlement in 2000. In July
2000, the defendants effectuated a settlement proposal, it
will be placed in a sub-class, whose claims will not be finalized as part of
the settlement approval. Corpus Christi has the right to opt out of this
subclass. The settlement proposal contemplates, among other things, that the
PG&E Corporation defendants would pay a total of not more than $12.2 million
to the settling class cities, inclusive of attorney fees, reduced by amounts
attributable to opt-out cities. The defendants retain the right to reject the
settlement if the settlement proposal is not approved by certain key cities
and by 80with approximately 70 percent of
the plaintiff class. Althoughclass members pursuant to which the defendants paid an aggregate of $63
million (inclusive of attorney's fees and expenses) in exchange for a
significant numbercomprehensive release from past liabilities and a license to use city rights-
of-way for 25 years. Settlement discussions continue with 21 of the 106 cities in22
remaining class members who are also class members of a pending class action
lawsuit involving a third party. Settlement discussions also continue with
the plaintiff class already have either approved the
settlement by enacting the ordinance, or adopted resolutions to pass the
ordinance, certain key cities and other cities have not approved the
settlement and have opted outcity of the settlement. Corpus Christi has opted out
of the general settlement, but is continuing to negotiate a possible sub-class
settlement with representatives of the class defendants. Representatives of
the class defendants and class counsel are negotiating changes to the
settlement. The settlement is also subject to final court approval.Christi.
PG&E Corporation believes that the ultimate outcome of these matters will
not have a material adverse impact on its financial position or its results of
operations. In January 2000, PG&E Corporation's National Energy Group signed
a definitive agreement to sell the stock of PG&E Gas Transmission, Texas
Corporation and PG&E Gas Transmission Teco, Inc. The buyer will assume all
liabilities associated with the cases described above.
Recorded Liability for Legal Matters:
In accordance with SFASStatement of Financial Accounting Standards (SFAS) No.
5, PG&E Corporation makes a provision for a liability when both it is probable
that a liability has been incurred and the amount of the loss can be
reasonably estimated. These provisions are reviewed quarterly and adjusted to
reflect the impacts of negotiations, settlements, rulings, advice of legal
counsel, and other information and events pertaining to a particular case.
The following table reflects the current year's activity to the recorded
liability for legal matters:
PG&E
Corporation Utility
------------ -----------
(in millions)
Beginning balance, January 1, 2000 $ 125126 $ 6970
Provisions for liabilities 1 114 14
Payments (4) (4)
Adjustments - -(7) (7)
----- -----
Ending balance, March 31,June 30, 2000 $ 122133 $ 6677
===== =====
NOTE 7: SEGMENT INFORMATION
PG&E Corporation has identified four reportable operating segments. The
Utility is one reportable operating segment and the other three are part of
the
PG&E National Energy Group. These four reportable operating segments provide
different products and services and are subject to different forms of
regulation or jurisdictions. PG&E Corporation's reportable segments are
described below.
Utility: PG&E Corporation's Northern and Central California energy
utility subsidiary, Pacific Gas and Electric Company, provides natural gas
and electric service to one of every 20 Americans.
PG&E National Energy Group: The PG&E National Energy Group businesses develop,
construct, operate, own, and manage independent power generation facilities
that serve wholesale and industrial customers through PG&E Generating Company,
LLC and its affiliates (collectively, PG&E Gen); own and operate natural gas
pipelines, natural gas storage facilities, and natural gas processing plants,
primarily in the Pacific Northwest and in Texas, through various subsidiaries
of PG&E Corporation (collectively, PG&E Gas Transmission or PG&E GT); and
purchase and sell energy commodities and provide risk management services to
customers in major North American markets, including the other PG&E National
Energy Group non-utility businesses, unaffiliated utilities, marketers,
municipalities, and large end-use customers through PG&E Energy Trading - Gas
Corporation, PG&E Energy Trading - Power, L.P., and their affiliates
(collectively, PG&E Energy Trading or PG&E ET). In the fourth
quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the
divestiture of PG&E Corporation'sCorporation has entered
into an agreement to sell its Texas natural gas and natural gas liquids
business.
Also in the fourth quarter of 1999, PG&E Corporation's Board of
Directors approved a plan for the divestiture of PG&E Corporation's retail
energy services, conducted through PG&E ES.
Segment information for the three and six months ended March 31,June 30, 2000 and
1999, respectively, was as follows:
Utility PG&E National Energy Group
------- -------------------------------------------
PG&E GT Elimi-
---------------- nations &
PG&EGen NW Texas PG&E ET Other (1) Total
------- ------- ------- ------- ------- -------
(in millions)
March 31, 2000
(in millions)
For the three months ended June 30, 2000
Operating revenues $ 2,2142,293 $ 310279 $ 4544 $ 212 $2,237208 $ (10)2,814 $ 5,008- $ 5,638
Intersegment revenues 43 2 12 13 320 (351)16 345 (378) -
------- ------- ------- ------- ------- ------- -------
Total operating revenues 2,218 312 57 225 2,557 (361) 5,0082,296 281 56 224 3,159 (378) 5,638
Income from
continuing operations 228 35 14216 20 13 - 11 (8) 280
Total assets at quarter end 21,357 3,865 1,149 1,183 1,886 (244) 29,196
March 31,2 (3) 248
For the three months ended June 30, 1999
Operating revenues $ 2,0832,231 $ 288253 $ 4639 $ 313397 $ 2,3961,767 $ -(5) $ 5,1264,682
Intersegment revenues 2 1 12 44 235 (294)13 39 257 (312) -
------- ------- ------- ------- ------- ------- -------
Total operating revenues 2,085 289 58 357 2,631 (294) 5,1262,233 254 52 436 2,024 (317) 4,682
Income from
continuing operations 147 32 15 (24)172 21 13 (8) 1 (3) 196
For the six months ended June 30, 2000
Operating revenues $ 4,507 $ 589 $ 88 $ 420 $ 5,051 $ (9) $10,646
Intersegment revenues 7 3 25 29 665 (729) -
167------- ------- ------- ------- ------- ------- -------
Total operating revenues 4,514 592 113 449 5,716 (738) 10,646
Income from
continuing operations 444 54 27 - 13 (10) 528
Total assets at quarter end 22,455 3,831 1,165 2,643 4,014June 30, 2000 22,124 3,810 1,134 1,259 3,042 (140) 31,229
For the six months ended June 30, 1999
Operating revenues $ 4,314 $ 541 $ 85 $ 710 $ 4,163 $ (5) $ 9,808
Intersegment revenues 4 2 25 83 492 (606) -
34,108------- ------- ------- ------- ------- ------- -------
Total operating revenues 4,318 543 110 793 4,655 (611) 9,808
Income from
continuing operations 319 56 28 (32) (2) (6) 363
Total assets at June 30, 1999 21,720 3,868 1,158 2,587 2,067 26 31,426
(1) Net income on intercompany positions recognized by segments using mark-to-market accounting
is eliminated. Intercompany transactions are also eliminated.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
- ---------------------------------------------
PG&E Corporation is an energy-based holding company headquartered in San
Francisco, California. PG&E Corporation's Northern and Central California
energy utility subsidiary, Pacific Gas and Electric Company (the Utility),
provides natural gas and electric service to one of every 20 Americans. The
PG&E
National Energy Group provides energy products and services throughout North
America.
The
PG&E National Energy Group businesses develop, construct, operate, own, and
manage independent power generation facilities that serve wholesale and
industrial customers through PG&E Generating Company, LLC (and its affiliates
(collectively, PG&E Gen); own and operate natural gas pipelines, natural gas
storage facilities, and natural gas processing plants, primarily in the
Pacific Northwest and in Texas, through various subsidiaries of PG&E
Corporation (collectively, PG&E Gas Transmission or PG&E
GT); and purchase and sell energy commodities and provide risk management
services to customers in major North American markets, including the other
PG&E National Energy Group non-utility businesses, unaffiliated utilities,
marketers, municipalities, and large end-use customers through PG&E Energy
Trading-Gas Corporation, PG&E Energy Trading-Power, L.P., and their affiliates
(collectively, PG&E Energy Trading or PG&E ET); and provide competitively priced electricity, natural
gas, and related services to industrial, commercial, and institutional
customers through PG&E Energy Services Corporation (PG&E Energy Services or
PG&E ES). PG&E Corporation has entered
into an agreement to sell its Texas natural gas and natural gas liquids business. PG&E Corporation also has
entered into an agreement to sell the stock of PG&E ES, through which the
buyer will acquire PG&E ES' retail electric and gas commodities
business.
This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and
Pacific Gas and Electric Company. It includes separate consolidated financial
statements for each entity. The condensed consolidated financial statements
of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility, and
PG&E Corporation's wholly owned and controlled subsidiaries. The condensed
consolidated financial statements of the Utility reflect the accounts of the
Utility and its wholly owned and controlled subsidiaries. This Management's
Discussion and Analysis (MD&A) should be read in conjunction with the
condensed consolidated financial statements included herein. Further, this
quarterly report should be read in conjunction with the Corporation's and the
Utility's Consolidated Financial Statements and Notes to Consolidated
Financial Statements incorporated by reference in their combined 1999 Annual
Report on Form 10-K.
This combined Quarterly Report on Form 10-Q, including this MD&A, contains
forward-looking statements about the future that are necessarily subject to
various risks and uncertainties. These statements are based on current
expectations and assumptions which management believes are reasonable and on
information currently available to management. These forward-looking
statements are identified by words such as "estimates," "expects,"
"anticipates," "plans," "believes," and other similar expressions. Actual
results could differ materially from those contemplated by the forward-looking
statements.
Factors that could cause future results to differ materially from those
expressed in or implied by the forward-looking statements or historical
results include:
- regulatory changes, including the pace and extent of the ongoing
restructuring of the electric and natural gas industries across the United
States;
- operational changes related to industry restructuring, including changes
in the Utility's business processes and systems;
- the method and timing of disposition and valuation of the Utility's
hydroelectric generation assets;
- the timingtime of the completion of the Utility's transition cost recovery and the
consequent end of the current electric rate freeze in California;California.
- any changes in the amount of transition costs the Utility is allowed to
collect from its customers;
- whether the Utility will be able to recover net generation-related
regulatory assets, including undercollected electric procurement costs, by the
end of the transition period;
- future operating performance at the Diablo Canyon Nuclear Power Plant
(Diablo Canyon);
- the method adopted by the California Public Utilities Commission (CPUC)
for sharing the net benefits of operating Diablo Canyon with ratepayers and
the timing of the implementation of the adopted method;
- the extent of anticipated growth of transmission and distribution services
in the Utility's service territory;
- future market prices for electricity;
- actions that certain regulators and legislatures may take steps to
mitigate the higher power prices in California;
- future fuel prices;
- future weather conditions;
- the success of management's strategies to maximize shareholder value in
the
PG&E National Energy Group, which may include acquisitions or dispositions of
assets, or internal restructuring;
- the extent to which our current or planned generation development projects
are completed and the pace and cost of such completion;
- generating capacity expansion and retirements by others;
- the successful integration and performance of acquired assets;
- the outcome of the Utility's various regulatory proceedings, including the
proposal to auction the Utility's hydroelectric generation assets, the
electric transmission rate case applications, and post-transition period
ratemaking proceedings;proceedings and the 2002 General Rate Case;
- fluctuations in commodity gas, natural gas liquids, and electric prices
and our ability to successfully manage such price fluctuations;
- the pace and extent of competition in the California generation market and
its impact on the Utility's costs and resulting collection of transition
costs;
- the effect of compliance with existing and future environmental laws,
regulations, and policies;policies, the cost of which could be significant; and
- the outcome of pending litigation.
As the ultimate impact of these and other factors is uncertain, these and
other factors may cause future earnings to differ materially from results or
outcomes we currently seek or expect. Each of these factors is discussed in
greater detail in this MD&A.
In this MD&A, we first discuss our competitive and regulatory environment.
We then discuss earnings and changes in our results of operations for the
quarters ended March 31,June 30, 2000 and 1999. Finally, we discuss liquidity and
financial resources, various uncertainties that could affect future earnings,
and our risk management activities. Our MD&A applies to both PG&E Corporation
and the Utility.
THE UTILITY
Transition Period, Rate Freeze, and Rate Reduction
- --------------------------------------------------
California's electric industry restructuring established a transition
period during which electric rates remain frozen at 1996 levels (with the
exception that, on January 1, 1998, rates for small commercial and residential
customers were reduced by 10 percent and remain frozen at this reduced level)
and investor-owned utilities may recover their transition costs. Transition
costs are generation-related costs that prove to be uneconomic under the new
competitive structure. The transition period ends the earlier of December 31,
2001, or when the particular utility has recovered its eligible transition
costs.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion (the expected revenue reduction from the rate decrease) of its
transition costs with the proceeds from the rate reduction bonds. The bonds
allow for the rate reduction by lowering the carrying cost on a portion of the
transition costs and by deferring recovery of a portion of these transition
costs until after the transition period. During the rate freeze, the rate
reduction bond debt service will not increase the Utility customers' electric
rates. If the transition period ends before December 31, 2001, the Utility may
be obligated to return a portion of the economic benefits of the transaction
to customers. The timing of any such return and the exact amount of such
portion, if any, have not yet been determined.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public purpose
programs, nuclear decommissioning, and rate reduction bond debt service.service, and the
cost of procuring electricity for the Utility's retail customers. To the
extent the revenues from frozen rates exceed authorized Utility costs, the
remaining revenues constitute the competitivecompetition transition charge (CTC), which
recovers the transition costs. These CTC revenues are being recovered from all
Utility distribution customers and are subject to seasonal fluctuations in the
Utility's sales volumes, fluctuating PX energy prices, and certain other
factors. As theThe CTC is collected regardless of the customer's choice of
electricity supplier (i.e., the CTC is non-bypassable),.
Authorized Utility costs in excess of revenues from frozen rates increase
the amount of costs deferred for future recovery. The deferred costs are
recoverable during the transition period when and if revenues from frozen
rates exceed authorized Utility believescosts. During the month of June 2000, the
Utility's current costs exceeded revenues provided by frozen rates by
approximately $700 million, primarily as a result of high electric procurement
prices.
High PX prices in June and July have caused certain regulators, legislators
and consumer advocates to express concern over the impact of high electricity
prices on customers after the transition period. Certain of these regulators
and legislators have suggested that regulatory intervention may be necessary
to mitigate the availability of
choice to its customers will not have a material impact on its ability to
recover transition costs.higher power prices in California.
Transition Cost Recovery
- ------------------------
Although most transition costs must be recovered during the transition
period, certain transition costs can be recovered after the transition period.
Except for certain transition costs discussed below, at the conclusion of the
transition period, the Utility will be at risk to recover any of its remaining
generation costs through market-based revenues.
Transition costs consist of (1) above-market sunk costs (costs associated
with utility generating facilities that are fixed and unavoidable and that
were included in customers' rates on December 20, 1995) and future sunk costs,
such as costs related to plant removal, (2) costs associated with long-term
contracts to purchase power at above-market prices from qualifying facilities
(QF) and other power suppliers, and (3) generation-related regulatory assets and
obligations. (In general, regulatory assets are expenses deferred in the
current or prior periods, to be included in rates in subsequent periods.)
Above-market sunk costs result when the book value of a facility exceeds
its market value. Conversely, below-market sunk costs result when the market
value of a facility exceeds its book value. The total amount of generation
facility costs to be included as transition costs is based on the aggregate of
above-market and below-market values. The above-market portion of these costs
is eligible for recovery as a transition cost. The below-market portion of
these costs will reduce other unrecovered transition costs. These above-Revenues
generated from the Utility's sales to the PX and below-market sunkISO that exceed authorized
costs are relatedalso used to generating facilities that are
classified as either non-nuclear or nuclear sunkoffset transition costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until the valuation of
the Utility's remaining non-nuclear generating assets, primarily its
hydroelectric generating assets, is completed. The valuation, through
appraisal, sale, or other divestiture, must be completed by December 31, 2001.
The value of seven of the Utility's other non-nuclear generating facilities
was determined when these facilities were sold to third parties. The portion
of the sales proceeds that exceeded the book value of these facilities was
used to reduce other transition costs. On September 30, 1999, the Utility
filed an application with the CPUC to determine the market value of its
hydroelectric generating facilities and related assets through an open,
competitive auction. (See "Generation Divestiture" below.) TheProvided an
alternative means of valuing the hydroelectric facilities is not used, the
Utility proposes to use an auction process similar to the one previously
approved by the CPUC and successfully used in the sale of the Utility's fossil
and geothermal plants. If the market value of the Utility's hydroelectric
facilities is determined based upon any method other than a sale of the
facilities to a third party, a material charge to Utility earnings could
result. Any excess of market value over book value would be used to reduce
other transition costs. (See "Generation Divestiture" below.)
For nuclear transition costs, revenues provided for transition cost
recovery are based on the accelerated recovery of the investment in Diablo
Canyon Nuclear Power Plant (Diablo Canyon) over a five-year period ending
December 31, 2001. The amount of nuclear generation sunk costs was determined
separately through a CPUC proceeding and was subject to a final verification
audit that was completed in August 1998. The audit of the Utility's Diablo
Canyon accounts at December 31, 1996, resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. The independent accounting firm also issued an agreed-upon special
procedures report, requested by the CPUC, that questioned $200 million of the
$3.3 billion sunk costs. The CPUC will review the results of the audit and
may seek to make adjustments to Diablo Canyon's sunk costs subject to
transition cost recovery. In May 2000, the Utility filed a petition at the
CPUC to close out the audit report without any changes in rates. The petition
is not opposed by the two consumer advocacy groups who originally requested
the audit, the Commission'sCPUC's Office of Ratepayer Advocates (ORA) and The Utility
Reform Network (TURN). At this time, the Utility cannot predict what actions,
if any, the CPUC may take regarding the audit report.
Costs associated with the Utility's long-term contracts to purchase
electric power are included as transition costs. Regulation required the
Utility to enter into such long-term agreements with non-utility generators.generators to
purchase electric power at fixed prices. Prices fixed under these contracts
are now typicallyhave generally been above prices for power in wholesale markets. Over the
remaining life of these contracts, the Utility estimates that it will purchase
299 million MWh of electric power. The contracts expire at various dates
through 2028. To the extent that the individual contract prices are above the
market price, the Utility is collecting the difference between the contract
price and the market price from customers, as a transition cost, over the term
of the contract. The contracts expire at various dates through 2028.To the extent that the contracted prices are below the
market price, the Utility is using the savings to offset other transition
costs during the transition period.
The total costs under long-term contracts are based on several variables,
including the capacity factors of the related generating facilities and future
market prices for electricity. For the threesix months ended March 31,June 30, 2000 and
1999, the average price paid under the Utility's long-term contracts for
electricity was 5.36.2 cents and 5.56.1 cents per kilowatt-hour (kWh), respectively.
The average costunconstrained price for base load electric energy (the price
received for a constant level of electricity purchasedelectric generation for all hours of electric
demand) sold at market rates frominto the California Power Exchange (PX)PX day-ahead market for the
threesix months ended March 31,June 30, 2000 and 1999, was 3.64.7 cents and 2.32.2 cents per kWh,
respectively.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At March 31,June 30, 2000 and December 31, 1999, the Utility's net generation-related net
regulatory assets, which include deferred electric procurement costs
(discussed below), totaled $4.4 billion and $4.0 billion.billion, respectively. These
regulatory assets increased by $439 million for the six months ended June 30,
2000, and decreased $813 million for the six months ended June 30, 1999.
Certain transition costs can be recovered through a non-bypassable charge
to distribution customers after the transition period. These costs include
(1) certain employee-related transition costs, (2) above-market payments under
existing long-term contracts to purchase power, discussed above, (3) up to $95
million of transition costs to the extent that the recovery of such costs
during the transition period was displaced by the recovery of electric
industry restructuring implementation costs, and (4) transition costs financed
by the rate reduction bonds. Transition costs financed by the issuance of rate
reduction bonds will be recovered over the term of the bonds. In addition,
the Utility's nuclear decommissioning costs are being recovered through a
CPUC-authorized charge, which will extend until sufficient funds exist to
decommission the nuclear facility. During the rate freeze, the charge for
these costs will not increase Utility customers' electric rates. Excluding
these exceptions, the Utility will write off any transition costs not
recovered during the transition period.
The Utility is amortizing its transition costs, including most generation-
related regulatory assets, over the transition period in conjunction with the
available CTC revenues. During the transition period, a reduced rate of
return on common equity of 6.77 percent applies to all generation assets,
including those generation assets reclassified to regulatory assets.
Effective January 1, 1998, the Utility started collecting these eligible
transition costs through the non-bypassable CTC, generation divestiture, and
generation divestiture.
Regulatory assets relatedother credits.
During the transition period, the CPUC reviews the Utility's compliance
with accounting methods established in the CPUC's decisions governing
transition cost recovery and the amount of transition costs requested for
recovery. In February 2000, the CPUC approved substantially all non-nuclear
transition costs that were amortized during the first six months of 1998. The
CPUC currently is reviewing non-nuclear transition costs amortized from July
1, 1998, to electric industry restructuring increased by $15
million for the quarter ended March 31, 2000, and decreased $247 million for
the quarter ended March 31,June 30, 1999.
Generation Divestiture
- ----------------------
In 1998, the Utility sold three fossil-fueled generation plants for $501
million. These three fossil-fueled plants had a combined book value at the
time of the sale of $346 million and a combined capacity of 2,645 megawatts
(MW).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled
plants had a combined book value of $256 million and had a combined capacity of
3,065 MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
The gains from the sale of the fossil-fueled generation plants were used to
offset other transition costs. Likewise, the loss from the sale of the
complex of geothermal generation facilities is being recovered as a transition
cost.
The Utility has retained a liability for required environmental remediation
related to any pre-closing soil or groundwater contamination at the plants it
has sold.
On September 30, 1999, the Utility filed anThe Utility's application with the CPUC to determine the market value of its
hydroelectric generating facilities and related assets through an open,
competitive auction. The Utility proposes to
use an auction process similaris currently pending at the CPUC. According to the one previously approved by the CPUC and
successfully usedCPUC's
revised procedural schedule, a draft environmental impact report is expected
to be published for public comment in the sale of the Utility's fossil and geothermal plants.
Under the process proposed in the application, the PG&E National Energy Group
would be permitted to participate in the auction on the same basis as other
bidders.
The sale of the hydroelectric facilities would be subject to certain
conditions, including the transfer or re-issuance of various permits and
licenses by the Federal Energy Regulatory Commission (FERC) and other
agencies. In addition, the FERC must approve assignment of the Utility's
Reliability Must Run Contract with the Independent System Operator (ISO) for
any facility subject to such contract. Under the proposed purchase and sale
agreement, the CPUC's approval of the proposed sale on terms acceptable to the
Utility in the Utility's sole discretion is also a condition precedent to the
closing of any sale.
The CPUC has ordered that the proceeding be divided into two concurrent
phases: one to review the potential environmental impacts of the proposed
auction under the California Environmental Quality ActSeptember 2000 and a second to
determine whether the Utility's auction proposal, or some other alternative to
the proposal, is in the public interest. The ruling sets a procedural
schedule that calls for a final CPUC decision
on the Utility's auction proposal by
October 19, 2000, and a final environmental impact report publishedis now expected in NovemberDecember 2000. The
ruling alsoschedule calls for the auction, if approved, to begin in mid-December. The
schedule anticipates that a final CPUC decision approving the sale would be
issued within 210 days from the adoption of the CPUC decision authorizing the
auction (i.e., by May 15, 2001. Finally, the ruling
prohibitsend of July 2001) and the divestiture process would be
closed within two weeks thereafter. The Utility and several other parties to
the proceeding, including TURN, the Agricultural Energy Consumers Association
(AECA), and the Coalition of California Utility Employees (CUE), have been
engaged in settlement discussions regarding the valuation and disposition of
the Utility's hydroelectric generating assets. The possible settlement being
discussed centers around a framework that includes the transfer of the
hydroelectric facilities at an agreed-upon value to a non-utility affiliate of
the Utility. Under this framework, the affiliate would hold and operate the
assets, subject to a revenue sharing contract between the affiliate and the
Utility that would permit the affiliate to recover an authorized inflation-
indexed operations and maintenance allowance, as well as a reasonable return
on capital investment. If revenue from withdrawing its application without expressthe hydroelectric facilities exceeds
the authorized costs, 90 percent of the excess revenue would be transferred to
the Utility and refunded to ratepayers. If the revenues fall short of the
authorized revenue requirement, 90 percent of any shortfalls would be billed
to the Utility by the affiliate and recovered from ratepayers.
Any settlement that may eventually be reached between any parties must be
submitted to the CPUC authority.for approval. Under the CPUC's rules, a settlement
proposal in this proceeding must be filed no later than August 14, 2000. It
is uncertain whether the CPUCexpected that a settlement proposal will ultimately approve the
Utility's auction proposal.
On February 17, 2000, the CPUC issued a decision in another proceeding, the
1998 Annual Transition Cost Proceeding (ATCP), that requires California
investor-owned utilities to estimate the market value of their remaining non-
nuclear generating assets, including the land associated with those assets, at
a value not less than the net book value of those assets on an aggregate basis
and to credit the Transition Cost Balancing Account (TCBA) with the estimated
value. The decision encourages the utilities to base such estimates on
realistic assessments of the market value of the assets. The decision
provides that if the estimated market valuation is less than book value for
any individual asset, accelerated amortization of the associated transition
costs will continue until final market valuation of the asset occurs through
sale, appraisal, or other divestiture. If the final value of the assets,
determined through sale, appraisal, or other divestiture, is higher than the
estimate, the excess amount would be used to reduce remaining transition
costs, if any. The utilities are required to file the adjusted entries to
their respective TCBA based on the estimated market valuesfiled with the CPUC by
May 31, 2000.for
approval before that date. The filing will become effective after appropriate review byCPUC may accept the CPUC's Energy Division and will be subjectproposed settlement or
reject it, suggest changes to review in the next ATCP. On
May 2, 2000,it, or adopt a proposed decision was issued recommending the establishment of
an accounting mechanism to permit a regulatory asset to be recorded equal to
the amount credited to the TCBA. If an estimate of the market value of the
non-nuclear generating assets is adopted that exceeds the aggregate net book
value of those assets, and if an appropriate accounting mechanism is not
adopted, a charge to earnings would result.different valuation approach.
At March 31,June 30, 2000, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.7 billion, excluding
approximately $0.5$0.4 billion of net investment reclassified as regulatory
assets. Any excess of market value over the $0.7 billion book value would be
used to reduce transition costs, including the remaining $0.5$0.4 billion of
regulatory assets related to the hydroelectric generation assets. If the
market value of the hydroelectric generation assets is determined by any
method other than a sale of the assets to aan unrelated third party, or if the winning
bidder for any of the auctioned assets is the PG&E National Energy Group, a material
charge to Utility earnings could result. The timing and nature of any such
charge is dependent upon the valuation method and procedure adopted, and the
method of implementation. As discussed above, it is possible that the
CPUC will require an interim valuation through an estimate of market value of
the assets prior to transfer, sale, or other divestiture, which could also
result in a material charge. While transfer or sale to an affiliated entity such
as the PG&E National Energy Group would result in a material charge to income,
neither PG&E Corporation nor the Utility believes that the sale of any
generation facilities to a third party will have a material impact on its
results of operations.
The Utility's ability to continue recovering its transitionnet generation-related
regulatory assets, which includes deferred electric procurement costs depends
on several factors, including (1) the continued applicationfederal and state regulatory implementation
of the regulatory framework established by the CPUC and state legislation, (2)
the amount of transition costs ultimately approved for recovery by the CPUC,
(3) the determined value of the Utility's hydroelectric generation facilities,
(4) future Utility sales levels, (5) future Utility fuel and operating costs, and (6)
the market price of electricity.electricity procured from and sold to the PX and ISO.
During the second quarter PX energy prices increased substantially, reducing
the amount of revenues from frozen rates available to recover transition
costs. Many factors influence the PX energy market, including weather,
availability of hydro-electric generation resources, demand, gas prices, and
the availability of generation resources. If the prices the Utility
experienced in June were to prevail throughout the remainder of the transition
period, the Utility would be unable to recover all of the net generation-
related regulatory assets, including its deferred electric procurement costs
by the end of the transition period. Given theits current evaluation of all
these factors, PG&E Corporation believes that the Utility will recover its
transition costs.these
regulatory assets. However, a changechanges in one or more of these factors could
affect the probability of recovery of transition coststhese regulatory assets and result in a
material charge.
Post-Transition Period
- ----------------------
The timing of the end of the rate freeze and corresponding transition
period will, in part, depend on the timing of the valuation of the Utility's
hydroelectric generating assets and the ultimate determined value of such
assets since any excess of market value over the assets' book value would be
used to reduce transition costs. If the value of the Utility's hydroelectric
generation assets is significantly higher than the related book value, the
transition period and the rate freeze could end before December 31, 2001,2001.
The CPUC has issued a decision which requires the Utility to refund to
electric customers any over-collected transition costs (plus interest at the
Utility's three-month commercial paper rate) within one year after the end of
the rate freeze. The decision also prohibits the Utility from collecting
after the rate freeze certain electric costs incurred during the rate freeze
but not recovered during the rate freeze, including under-collected accounting
balances relating to power purchases, such as power purchased from the PX. At
June 30, 2000, the aggregate balance of these accounts was approximately $700
million. The CPUC decision prohibits offsetting these specific accounts
against over-collected transition costs. The Utility has appealed this
decision in the California Court of Appeals and potentially could end during 2000.a decision is pending.
The CPUC also has established the Purchased Electric Commodity Account
(PECA) for the Utility to track energy costs after the rate freeze and
transition period end. In October 1999,June 2000, the CPUC issued a decision in the second
phase of the Utility's post-
transitionpost-transition period electric ratemaking proceeding.
Among other matters,things, the CPUC'sCPUC determined that the PECA would reflect a pass-
through of energy costs, possibly subject to after-the-fact reasonableness
reviews. The decision addressesdetermines that after the mechanisms for ending the currentrate freeze ends there will be
two electric rate freeze
and for establishing post-transition period accounting mechanismsproceedings which will, among other things, address electric
energy procurement practices and rates.
The decision prohibitsAfter the Utility from continuing to price electric
generation fromrate freeze ends Diablo Canyon based onwill be operated as a competitive
generator of electricity with revenues generated from prevailing market rates.
During the rate freeze Diablo Canyon's operating costs have been recovered as
a non-transition cost through the incremental cost incentive price (ICIP) after the transition period has ended..
The ICIP, which has been in place since January 1, 1997, is a performance-basedperformance-
based mechanism that establishes a rate per kWhkilowatt-hour (kWh) generated by
the facility. The ICIP prices for 1999, 2000, and 2001 are 3.37 cents per
kWh, 3.43 cents per kWh, and 3.49 cents per kWh, respectively. The average
price for base load electric energy (the price
received for a constant level of electric generation for all hours of electric
demand) sold at market rates to the California PX for the three-month periods
ended March 31, 2000 and 1999, was 3.6 cents and 2.3 cents per kWh,
respectively. The averageunconstrained price for base load electric energy sold at market rates tointo
the California PX day-ahead for the 12 months ending March 31,six-month periods ended June 30, 2000 and
1999, was 4.04.7 cents and 2.2 cents per kWh. Future market prices may be higher or lower. Under the CPUC's
decision, after the transition period, the Utility must price Diablo Canyon
generation at the prevailing market price for power.
ThekWh, respectively.
As required by a prior CPUC decision requires the Utility to provide quarterly forecasts of
when the Utility's rate freeze (i.e., transition period) may end based on various assumptions regarding energy prices and the market value of the
Utility's remaining generation assets. The Utility is required to notify the
CPUC three months before the earliest forecasted end of its rate freeze and
provide draft tariff language and sample calculations of the rates that would
go into effect when the rate freeze ends. After the Utility completes its
transition cost recovery, it must implement its post-rate-freeze rates.
After the rate freeze and transition periods end, the Utility must refund
to electric customers any over-collected transition costs (plus interest at
the Utility's three-month commercial paper rate) within one year after the end
of the rate freeze. The Utility also will be prohibited from collecting after
the rate freeze certain electric costs incurred during the rate freeze but not
recovered during the rate freeze, including costs that are not classified as
transition costs and are not related to generation assets such as under-
collected accounting balances relating to power purchases. Through the end of
its rate freeze, the Utility will continue to incur certain non-transition
costs and place those costs into balancing and memorandum accounts for future
recovery. There is a risk that the Utility will be unable to collect certain
non-transition costs that, due to lags in the regulatory cost approval
process, have not been approved for recovery nor collected when the rate
freeze ends. The Utility is unable to predict the amount of such potential
unrecoverable costs.
In November 1999,June 30, 2000, the Utility filed
an application with the CPUC requesting approval of its proposal for rehearingsharing
with ratepayers 50 percent of the CPUC's decision. In March 2000, the CPUC deniedpost-rate freeze net benefits of operating
Diablo Canyon in electricity markets. The net benefit sharing methodology
proposed in the Utility's application would be effective at the end of the
current electric rate freeze for rehearing on the issues of Diablo Canyon ICIPUtility's customers and post-transition period
recovery of non-transition costs. On April 17, 2000,would continue
for as long as the Utility filed a
petition for review inowned Diablo Canyon. Under the California Court of Appeal on the issue of post-
transition period recovery of non-transition costs.
The CPUC also has established the Purchased Electric Commodity Account
(PECA) for the Utility to track energy costs after the rate freeze and
transition period end. The CPUC intends to explore other ratemaking issues,
including whether dollar-for-dollar recovery of energy costs is appropriate,
in the second phase of the post-transition period electric ratemaking
proceeding. There are three primary options for the future regulatory
framework for utility electric energy procurement cost recovery after the rate
freeze: (1) a CPUC-defined procurement practice, that if followed byproposal, the
Utility would pass through costs without the need for reasonableness reviews,
(2) a pass-through of costs subject to after-the-fact reasonableness reviews,
or (3) a procurement incentive mechanism with rewards and penalties determined
based on the Utility's energy purchasing performance compared to a benchmark.
The Utility proposed adoption of either a defined procurement practice or a
procurement incentive mechanism, neither of which would involve reasonableness
reviews. On March 17, 2000, the CPUC issued a proposed decision that states
that after the rate freeze, there will be two electric rate proceedings to
address electric energy procurement practices and rates. The Revenue
Adjustment Proceeding (RAP) will be a forecast of costs, and the ATCP will
include a review of procurement costs to the extent costs above the wholesale
PX rate are included in the PECA. The volatility of earnings and risk
exposure of the Utility related to post-transition period purchases of
electricity is dependent on which of these options, or some other approach, is
adopted.
Further, pursuant to the 1997 CPUC decision establishing the ICIP, the
Utility is required to begin sharing 50 percent ofshare the net benefits of operating Diablo Canyon based on the
audited profits from operations, consistent with ratepayers at the endprior CPUC decision. If
Diablo Canyon experiences losses, such losses would be accrued and netted
against profits in the calculation of the transition period.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 Utility's sharing proposal is subject to comments by other parties and
possibly evidentiary hearings. The Utility is required to file an application by July 2000 with its proposalhas proposed that the CPUC adopt a
procedural schedule that calls for the methodsa final decision to be usedissued in the valuationfirst
quarter of 2001. The CPUC may decide to implement a different procedural
schedule than proposed by the benefits associated with
the operation of Diablo Canyon, and the mechanism to be used to share these
benefits with ratepayers.Utility. The Utility and PG&E Corporation are
unable to predict what type of valuation and sharing mechanism will be adopted
and what the ultimate financial impact of the sharing mechanism will have on
results of operationoperations or financial position.
The ultimate financial impact of the provisionsend of the post-transition
period issues discussed above will depend on the date the Utility's transition
cost recovery is completed and the rate freeze ends,will depend
upon future costs including
Diablo Canyon operating costs, futurePX and ISO market prices for electricity,during the method adopted by the CPUC for sharing net benefits of operating Diablo Canyon
with ratepayers,transition period, the amount
of any electric non-transition costs that have been incurred but not recovered
as of the end of the rate freeze, the timing of various regulatory proceedings
in which the Utility seeks approval for rate recovery of various costs incurred
during the rate freeze, and other variables that PG&E Corporation and the
Utility are unable to predict.
After the transition period, it is possible that the Utility's future earnings
from its electric distribution and transmission operations will be subject to
volatility due to sales fluctuations.
Distributed Generation and Electric DistributionFuture Competition
- ------------------------------------------------------------
In October 1999, the CPUC issued a decision outlining how the CPUC,------------------
Opening California's electric generation to competition has raised interest
in cooperation with other regulatory agencies and the California Legislature,
plans to address the issues surrounding distributed generation, electric
distributionintroducing further competition and the role of the utility distribution companies
(such as Pacific Gas and Electric Company) in the competitive retail electric market. Distributedindustry. The CPUC has
opened a rulemaking proceeding to examine the various issues associated with
distributed generation. Distribution generation enables the siting of
electric generation technologies in close proximity to the electric demand
(referred to as "load")., and raises issues about stranded costs - both within
distribution and transmission systems, interconnection charges and cost
allocation. The CPUC decision openedstaff has issued a new rulemaking proceeding to examine
various issues concerning distributed generation, including interconnection
issues, who can ownreport identifying options for
possible CPUC consideration regarding the additional unbundling of the
electric distribution function and operate distributed generation, environmental impacts,evaluate the investor owned utilities' role
of utility distribution companies,default provider of electricity.
It is too early to predict what may come of these matters. PG&E
Corporation is unable to predict when these issues will be addressed by the
CPUC and the rate design and cost
allocation issues associated withCalifornia legislature or whether the deployment of distributed generation
facilities. With respect to electric distribution competition, the CPUC
directed its staff to deliver a report by June 2, 2000,results will have any
impact on the different
policy options that the CPUC, in cooperation with the California Legislature,
can pursue. Following the issuance of the report, the CPUC expects to open
one or more new proceedings to address electric distribution competition and
competition in the retail electric market.Utility.
PG&E NATIONAL ENERGY GROUP
The
PG&E National Energy Group has been formed to pursue opportunities created
by the gradual restructuring of the energy industry across the nation. The PG&E
National Energy Group integrates our national power generation, gas
transmission, and energy trading and services businesses. The PG&E National Energy Group
contemplates increasing PG&E Corporation's national market presence through a
balanced program of acquisition and development of energy assets and
businesses, while at the same time undertaking ongoing portfolio management of
its assets and businesses. The PG&E National Energy Group's ability to anticipate
and capture profitable business opportunities created by restructuring will
have a significant impact on PG&E Corporation's future operating results.
Independent Power Generation
- ----------------------------
Through PG&E Gen and its affiliates, we participate in the development,
construction, operation, ownership, and management of non-utility electric
generating facilities that compete in the United States power generation
market. In September 1998, PG&E Corporation, through its indirect subsidiary
USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of
electric generation assets and power supply contracts from the New England
Electric System (NEES). The purchased assets include hydroelectric, coal,
oil, and natural gas generation facilities with a combined generating capacity
of about 4,000 MW.
As part of the New England electric industry restructuring, the local
utility companies were required to offer Standard Offer Service (SOS) to their
retail customers. Retail customers may select alternative suppliers at any
time. The SOS is intended to provide customers with a price benefit (the
commodity electric price offered to the retail customer is expected to be less
than the market price) for the first several years, followed by a price
disincentive that is intended to stimulate the retail market.
Retail customers may continue to receive SOS through June 30, 2002, in New
Hampshire (subject to early termination on December 31, 2000, at the
discretion of the New Hampshire Public Service Commission), through December
31, 2004, in Massachusetts, and through December 31, 2009, in Rhode Island.
However, if customers choose an alternate supplier, they are precluded from
going back to the SOS.
In connection with the purchase of the generation assets, USGenNE entered
into wholesale agreements with certain of the retail companies of NEES to
supply at specified prices the electric capacity and energy requirements
necessary for their retail companies to meet their SOS obligations. These
companies are responsible for passing on to us the revenues generated from the
SOS. USGenNE currently is indirectly serving a large portion of the SOS
electric capacity and energy requirements for these companies, except in New
Hampshire. For the threesix months ended March 31,June 30, 2000, the contract SOS price
paid to generators was $0.038$.038 per kWh for generation. On March 1, 1999,
Constellation Power Source, Inc. (Constellation) won the New Hampshire component of the SOS
through a competitive bidding solicitation. On January 7, 2000, USGenNE paid
approximately $15 million to a third party for this third party's assumption
of 10 percent of the Massachusetts Electric Company/Nantucket Electric Company
SOS and 40 percent of the Narragansett SOS.
Like other utilities, New England utilities previously entered into
agreements with unregulated companies (e.g., qualifying facilities under the
Public Utility Regulatory Policies Act of 1978 (PURPA)) to provide energy and
capacity at prices that are anticipated to be in excess of market prices. We
assumed NEES' contractual rights and duties under several of these power
purchase agreements. At March 31,June 30, 2000, these agreements provided for an
aggregate 655470 MW of capacity. However, NEES will make support payments to us
toward the cost of these agreements. The support payments by NEES total $0.9
billion in the aggregate (undiscounted) and are due in monthly installments
from September 1998 through January 2008. In certain circumstances, with our
consent, NEES may make a full or partial lump-sumlump sum accelerated payment.
Initially, approximately 90 percent of the acquired operating capacity,
including capacity and energy generated by other companies and provided to us
under power purchase agreements, is dedicated to servicing SOS customers.
Currently, approximately 60 percent to 70 percent of the capacity is dedicated
to serving SOS customers. To the extent that customers eligible to receive
SOS choose alternate suppliers, or as these obligations are sold to other
parties, this percentage will continue to decrease. As customers choose
alternate suppliers, or the SOS obligations are sold, a greater proportion of
the output of the acquired operating capacity will be subject to market
prices.
Gas Transmission Operations
- ---------------------------
PG&E Corporation participates in the "midstream" portion of the gas
business through PG&E GT NW. PG&E GT NW owns and operates gas transmission
pipelines and associated facilities which extend over 612 miles from the
Canada-U.S. border to the Oregon-California border. PG&E GT NW provides firm
and interruptible transportation services to third party shippers on an open-
access basis. Its customers are principally retail gas distribution
utilities, electric utilities that use natural gas to generate electricity,
natural gas marketing companies, natural gas producers, and industrial
consumers.
On January 27, 2000, the PG&E National Energy Group signed a definitive
agreement with El Paso Field Services Company (El Paso) providing for the sale
to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of PG&E Gas Transmission, Texas
Corporation and PG&E Gas Transmission Teco, Inc. (collectively, PG&E GT-Texas)GT-
Texas). The consideration to be received by the PG&E National Energy Group
includes $279 million in cash, subject to aadjustments for working capital, adjustment,and
includes the assumption by El Paso of liabilities associated with PG&E GT-
Texas and debt having a book value of $624 million, and other liabilities associated with PG&E GT-Texas.
approximately $570 million.
In 1999, PG&E Corporation recognized a charge against earnings of $890
million after tax, or $2.42 per share, to reflect PG&E GT-Texas' assets at
their fair market value. The composition of the pre-tax charge is as follows:
(1) an $819 million write-down of net property, plant, and equipment, (2) the
elimination of the unamortized portion of goodwill, in the amount of $446
million, and (3) an accrual of $10 million representing selling costs.
Proceeds from the sale will be used to retire short-term debt associated
with PG&E GT-Texas' operations and for other corporate purposes. Closing of
the sale, which is expected in the first halfthird quarter of 2000, is subject to
approval under the Hart-Scott-Rodino Act.
Energy Trading
- --------------
Through PG&E ET, we purchase bulk volumes of power and natural gas from
PG&E Corporation affiliates and the wholesale market. We then schedule,
transport, and resell these commodities, either directly to third parties or
to other PG&E Corporation affiliates. PG&E ET also provides risk management
services to PG&E Corporation's other businesses (except the Utility) and to
wholesale customers. (See "Price Risk Management Activities" below; and Note
3 of the Notes to Condensed Consolidated Financial Statements.)
Energy Services
- ---------------
In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E ES, its wholly owned subsidiary, through a sale. The intended
disposal has been accounted for as a discontinued operation. In connection
with this transaction, PG&E Corporation's investment in PG&E ES was written
down to its estimated net realizable value in 1999. In addition, in 1999,
PG&E Corporation provided a reserve for anticipated losses through the date of
sale. The total provision for discontinued operations was $58 million, net of
income taxes of $36 million. During the threesix month period ended March 31,June 30, 2000,
$14.7$28.5 million was charged against this reserve. On April 12,June 29, 2000, the PG&E
National Energy Group signed an agreement to sell specified assets,
liabilities, and contractscompleted its sale of the energy commodities portfolio
of its energy services business, PG&E Energy Services Corporation. The
consideration to be received by the PG&E National Energy Group isCorporation, for $20
million, plus net working capital of approximately $65 million, for a total of
$85 million. The transaction is expected to close by June 2000. The remaining
componentsIn addition, the sale of PG&E Energy Services Corporation, mainly the Value Added Services business and
various other assets will continue to be offeredwas completed on July 21, 2000, for sale. Thea consideration of
$18 million. PG&E National Energy Group expects to complete this disposition
prior to year-end 2000. The dispositionis seeking a buyer for the remainder
of the assets formerly held by PG&E ES has been reflected in the
financial statements as a discontinued operation.ES. The PG&E ES business segment generated
net losses of $8$25 million (or $0.02$0.07 per share) for the three-monthsix-month period ended
March 31,June 30, 1999.
REGULATORY MATTERS
A significant portion of PG&E Corporation's operations are regulated by
federal and state regulatory commissions. These commissions oversee service
levels and, in certain cases, PG&E Corporation's revenues and pricing for its
regulated services. The Utility is the only subsidiary with significant
regulatory proceedings at this time. Any change in authorized electric
revenues resulting from any of the electric proceedings discussed below would
not impact the Utility's customer electric rates during the transition period
because these rates are frozen throughout the transition period.frozen. However, any change would affect the amount
of revenues available for the recovery of transition costs. Any change in
authorized gas revenues resulting from gas proceedings would result in a
change in the Utility's customer gas rates. The Utility's pending proceedings
to determine the value of its hydroelectric generation assets and the method
for sharing the net benefits of operating Diablo Canyon with ratepayers after
the rate freeze are discussed above.
The 1999 General Rate Case (GRC)
- --------------------------------
The CPUC's final decision issued in February 2000 in the Utility's 1999 GRC
application increased annual electric distribution revenues by $163 million
and annual gas distribution revenues by $93 million, as compared to revenues
authorized for 1998. Although the increase in electric and gas distribution
revenues was retroactive to January 1, 1999, prior quarters were not restated.
Instead, the entire increase was reflected in the fourth quarter of 1999. Had
the Utility restated prior quarters, 1999 first quarter net earnings for the six months
ended June 30, 1999, would have been $40$80 million higher than reported.
The Utility's GRC application also contained a proposal for an Attrition
Rate Adjustment (ARA) to adjust revenues in 2000 and 2001. The ARA would
increase authorized revenues to offset cost increases during these periods.
The final decision denies the Utility's request for an ARA to adjust revenues
in 2000, but adopts an ARA for 2001. The final decision orders that the CPUC
oversee an audit of the Utility's 1999 distribution capital spending, and that
the 2001 ARA be subject to modification to take into account the results of
the audit. The 2001 ARA will also be subject to modification to recognize
amounts recorded in a new balancing account that the final decision requires
be established for vegetation management expenses.
In March 2000, two intervenors filed applications for rehearing of the GRC
decision, alleging that the CPUC committed legal errors by approving funding
in certain areas that were not adequately supported by record evidence. In
April 2000, the Utility filed its response to these applications for
rehearing, defending the GRC decision against the allegations of error. A
CPUC decision on the applications for rehearing is expected in the second quarterhalf
of 2000.
The 2002 General Rate Case (GRC)
- --------------------------------
Also in the 1999 GRC final decision, the CPUC ordered the Utility to file a
2002 GRC. TheOn July 20, 2000, the CPUC issued a decision requiring the Utility currently intends
to file a Notice of Intent with the CPUC by May 1, 2001, a delay of nine
months compared to the procedural timetable in effect for the third quarter of 2000. This date may be extended, depending upon
the outcome of an April 27, 2000 ruling from two1999 GRC. The
CPUC Commissioners,
requesting comments on whether the CPUC should delay the Utility's 2002 GRC by
six months. In seeking these comments, the Commissioners stateddecision affirms that if the
2002 GRC were delayed, rates couldwould still become effective on January 1,
2002, although the CPUC decision may not be rendered until mid-2002.late 2002.
The 2001 Attrition Rate Adjustment (ARA)
- ----------------------------------------
On July 27, 2000, the Utility filed an ARA application with the CPUC to
increase its 2001 electric distribution revenues by $189 million, effective
January 1, 2001, to reflect inflation and the growth in capital investments
necessary to serve customers. The Utility did not request an increase in gas
distribution revenues. The Utility has requested expedited treatment of the
application and has proposed a schedule to ensure that the 2001 ARA decision
is issued before January 1, 2001. The Utility has requested that this
application be resolved without evidentiary hearings.
The Year 2000 Cost of Capital Proceeding
- ----------------------------------------
In AprilJune 2000, the Utility reachedCPUC issued a settlement withfinal decision in the ORA and several
intervenor groups and will make a joint recommendation to the CPUC. The joint
recommendation specifiesUtility's 2000 cost
of capital proceeding, adopting a return on common equity (ROE) of 11.22
percent on electric and gas distribution operations, retroactive to February
17, 2000.
The2000, as compared to the Utility's currentformer authorized ROE isof 10.6 percent.
The joint
recommendationdecision also recommends no changes toaffirmed the currentlyexisting authorized Utility capital structure
of 46.2 percent long-term debt, 5.8 percent preferred stock, and 48.0 percent
common equity.
If adopted by the CPUC, the recommendation would resultThe decision results in an authorized 9.12 percent overall return on
Utility electric and gas distribution rate base. This would increase theThe Utility's 2000 electric
and gas revenues will increase by approximately $37 million and $12 million,
respectively.
A final CPUC decision onrespectively, for the parties' recommendation is expected in the
second quarter ofperiod February 17, 2000, through December 31, 2000.
The Year 2001 Cost of Capital Proceeding
- ----------------------------------------
On May 8, 2000, the Utility filed an application with the CPUC to establish
its authorized rate of return (ROE)(ROR) for electric and gas distribution
operations for 2001. The application requests a ROE of 12.4 percent, and an
overall rate of return (ROR)ROR of 9.75 percent. The Utility's proposal for test year 2001 ROE
for its electric distribution and gas distribution lines of business is 118 basis points1.18
percent higher than the 2000 settlement ROE of 11.22 percent currently pending before the CPUC.percent. If granted, the requested
ROEROR would increase electric distribution revenues by approximately $72 million
and gas distribution revenues by approximately $23 million, as compared with the
2000 settlement ROE of 11.22 percent currently pending before the CPUC.million. The application
also requests authority to implement an Annual Cost of Capital Adjustment
Mechanism for 2002 through 2006 that would replace the annual cost of capital
proceedings. The proposed adjustment mechanism would modify the Utility's
cost of capital based on changes in an interest rate index. The Utility also
proposes to maintain its currently authorized capital structure of 46.2
percent long-term debt, 5.8 percent preferred stock, and 48.0 percent common
equity.
FERC Transmission Rate Cases
- ----------------------------
Since April 1998, electric transmission revenues have been authorized by
the FERC, including various rates to recover transmission costs from the
Utility's former bundled retail transmission customers. The FERC has not yet
acted upon a settlement filed by the Utility that, if approved, would allow
the Utility to recover $345 million in electric transmission rates for the 14-
month period of April 1, 1998 through May 31, 1999. During this period,
somewhat higher rates have been collected, subject to refund. However, in
April 2000, the FERC approved a settlement that permits the Utility to recover
$264 million in electric transmission rates for the 10-month period of May 31,
1999 to March 31, 2000. Further, in October 1999, the FERC accepted, subject
to refund, the Utility's proposal to collect $370 million annually in electric
transmission rates beginning on April 1, 2000. In May 2000, a settlement was
filed with the FERC that, if approved by the FERC, would provide for rates
which would collect $340 million annually. The Utility does not expect a
material impact on its financial position or results of operations resulting
from these matters.
Catastrophic Event Memorandum Account Proceeding
- ------------------------------------------------
As previously disclosed, in September 1999, the Utility entered into a
settlement agreement with the ORA, and other parties, providing for an
increase in electric and gas distribution revenue requirements to compensate
the Utility for service restoration costs recorded in the Catastrophic Events
Memorandum Account. In April 2000, the CPUC approved the proposed settlement
and collection over the remainder of the year.
The CPUC's Gas Strategy Investigation, Phase 2
- ----------------------------------------------
In January 1998, the CPUC opened a rulemaking proceeding to explore
changesalternative market structures in the natural gas industry in California. In July 1999, the CPUC issued a
decision identifying options for restructuring the natural gas industry. In
the decision, the CPUC reaffirmed the basic structure of the Gas Accord. The
CPUC further stated that it seeks to explore a market structure that maintains
the utilities' traditional role of providing fully integrated default service
while removing obstacles to competitive unbundled services. The CPUC opened a
new investigative proceeding to explore in more detail the anticipated costs
and benefits associated with the different market structure options it has
identified. In
January 2000, the Utility and a broad-based coalition of shippers, consumer
groups, marketers, and others filed a settlement with the CPUC which
would reaffirmreaffirmed the basic structure of the Gas Accord and would continue the Gas
Accord through its original term of December 31, 2002. On May 18, 2000, the
CPUC approved the uncontested settlement.
Performance-Based Ratemaking (PBR) Application
- ----------------------------------------------
In June 2000, the CPUC granted the Utility's request to withdraw its PBR
application filed in November 1998. The Utility had requested the withdrawal
in accordance with the 1999 General Rate Case decision issued in February
2000, which required a 2002 GRC before a PBR revenue/rate indexing mechanism
could be implemented. In closing the PBR proceeding, the CPUC ordered the
Utility to file a new PBR application by September 1, 2000, for financial
rewards/penalties associated with utility performance in meeting prescribed
standards on measures such as electric reliability and customer service.
RESULTS OF OPERATIONS
The table below shows for the quarterthree and six months ended March 31,June 30, 2000 and
1999, certain items from our Statement ofCondensed Consolidated Income Statement detailed
by Utility and PG&E National Energy Group operations of PG&E Corporation. (In
the "Total" column, the table shows the combined results of operations for
these groups.) The information for PG&E Corporation (the "Total" column)
excludes transactions between its subsidiaries (such as the purchase of natural gas by
the Utility from the unregulated business operations).subsidiaries. Following this table we
discuss earnings and explain why the components of our results of operations varied from the quarter for 2000.operations.
Utility PG&E National Energy Group
------- ---------------------------------------------
PG&E GT Elimi-
---------------- nations &
PG&EGen NW Texas PG&E ET Other (1) Total
------- ------- ------- ------- ------- --------- -------
(in millions)
March 31,(in millions)
For the three months ended June 30, 2000
- --------------
Operating revenues $ 2,2182,296 $ 312281 $ 5756 $ 225224 $ 2,5573,159 $ (361)(378) $ 5,0085,638
Operating expenses 1,648 255 25 210 2,544 (350) 4,3321,744 251 24 223 3,158 (384) 5,016
------- ------- ------- ------- ------- ------------- -------
Operating income 570 57 32 15 13 (11) 676622
Other income, net 1512
Interest expense 183182
Income taxes 228204
Income from continuing
operations 280248
Net income $ 280248
EBITDA (2) $ 864580 $ 7851 $ 4243 $ 12(3) $ 172 $ (10)5 $ 1,003
March 31,678
For the three months ended June 30, 1999
- --------------
Operating revenues $ 2,0852,233 $ 289254 $ 5852 $ 357436 $ 2,6312,024 $ (294)(317) $ 5,1264,682
Operating expenses 1,663 243 27 383 2,636 (287) 4,6651,781 244 23 444 2,024 (314) 4,202
------- ------- ------- ------- ------- ------------- -------
Operating income 422 46 31 (26) (5) (7) 461480
Other income, net 2140
Interest expense 201192
Income taxes 114132
Income from continuing
operations 167196
Net income $ 171182
EBITDA (2) $ 795954 $ 7042 $ 4140 $ (7)12 $ (3)2 $ (7)(27) $ 8891,023
For the six months ended June 30, 2000
Operating revenues $ 4,514 $ 592 $ 113 $ 449 $ 5,716 $ (738) $10,646
Operating expenses 3,392 506 49 433 5,702 (734) 9,348
------- ------- ------- ------- ------- ------- -------
Operating income 1,298
Other income, net 27
Interest expense 365
Income taxes 432
Income from continuing
operations 528
Net income $ 528
EBITDA (2) $ 1,433 $ 129 $ 85 $ 9 $ 19 $ (5) $ 1,670
For the six months ended June 30, 1999
Operating revenues $ 4,318 $ 543 $ 110 $ 793 $ 4,655 $ (611) $ 9,808
Operating expenses 3,444 487 50 827 4,660 (601) 8,867
------- ------- ------- ------- ------- ------- -------
Operating income 941
Other income, net 61
Interest expense 393
Income taxes 246
Income from continuing
operations 363
Net income $ 353
EBITDA (2) $ 1,749 $ 108 $ 81 $ 5 $ (1) $ (46) $ 1,896
(1) Net income on intercompany positions recognized by segments using mark to marketmark-to-market accounting is
eliminated. Intercompany transactions are also eliminated.
(2) EBITDA measures earnings (after preferred dividends) before interest expense (net of interest
income), income taxes, depreciation, and amortization.
Overall Results
- ---------------
PG&E Corporation's net income for the firstsecond quarter of 2000 increased 63.736.3
percent to $280$248 million from $171$182 million in the prior year's firstsecond quarter.
Of the $109$66 million increase, the PG&E National Energy Group accounted for $28$22
million of the increase and the Utility's first quarter net income available
for common stock increased to $228$216 million from $147$172 million in the prior
year.
Net income for the six-month period ended June 30, 2000 increased 49.6
percent to $528 million from $353 million for the same period in 1999. Of the
$175 million increase, PG&E National Energy Group accounted for $50 million of
the increase and the Utility's net income available for common stock for the
first six months of 2000 increased to $444 million from $319 million in the
comparable period of the prior year.
The strong increase in performance is attributable to the following factors:
- In the first quarter of 2000, the Utility received the final order on its
general rate case. Although the increase in revenue requirements was
retroactive to January 1, 1999, the prior quarters were not restated and the
entire increase was reflected in the fourth quarter of 1999. The outcome of
the rate order increased firstsecond quarter Utility net earnings approximately $40
million ($0.11 per share) and year-to-date earnings approximately $80 million
($0.22 per share) compared to the second quarter and first quarterhalf of 1999.1999,
respectively.
- In the firstsecond quarter of 1999, Diablo Canyon completed2000, the Utility received a scheduled refueling
outage for onefinal decision from
the CPUC increasing its authorized cost of its plants. There was no such outage during the first
quarter ofcapital from 10.6 percent to 11.22
percent, retroactive to February 2000, resulting in an approximate $36$12 million
($0.100.03 per share) increase in 2000 second quarter and first quarterhalf net earnings.
- PG&E ET's firstsecond quarter 2000 net income before restructuring charges
increased $14$6 million over 1999 firstsecond quarter results due to across the board
improvements in gas and power trading, in asset management and structured
transactions. This increase was net ofoffset by a $4$5 million after-tax ($.01 per
share) charge for severance costs associated with the restructuring of the PG&E National Energy
Group. PG&E ET's net income for the first half of 2000, net of restructuring
charges of $9 million after-tax ($0.02 per share), has increased $15 million
compared to the same period of 1999.
- At the end of 1999, PG&E Corporation announced its plans to dispose of PG&E
GT-Texas and PG&E ES in separate transactions. The PG&E GT-Texasthese assets were written down to estimated fair valuevalue. PG&E GT
Texas has operated at a breakeven basis in 2000 and the PG&E ES assets were reflected as
discontinued operations. Netreported losses associated with those business segments
amounted toof $8
million ($0.02 per share) and $32 million ($0.080.09 per share) infor the first quarter of 1999.three and
six months ended June 30, 1999, respectively.
- Effective the first quarter of 1999, PG&E Corporation changed its method of
accounting for major maintenance and overhauls at PG&E National Energy Group.
Beginning January 1, 1999, the cost of major maintenance and overhauls,
principally at the PG&E Gen business segment, have been accounted for as
incurred. The change resulted in PG&E Corporation recording income of $12
million after-tax ($0.03 per share), reflecting the cumulative effect of the
change in accounting principle.
EBITDA has increased 12.8 percent to $1,003 million from $889 million inprinciple for the prior year's first quarter as a resulthalf of the increased operating
performance of the Utility and PG&E ET described above.1999.
Operating Revenues
- ------------------
Utility operating revenues increased $133$63 million and $196 million in the
second quarter and first quarterhalf of 2000, respectively, compared to $2.2 billion over first quarter 1999 revenuesthe similar
periods of $2.1 billion.the prior year. The increase is a result of higher electric sales
to residential customers reflecting an increase in the number of customers and
to industrial customers due to an increase in the average customer usage.
This increase was partially offset by
a decreaseAdditionally, increases in naturalthe price of gas sales because of milder winter weather.have increased revenues.
PG&E National Energy Group operating revenues declined $251increased $893 million and
$642 million in the second quarter and first quarterhalf of 2000, respectively,
compared to the first quartersimilar periods of 1999. The decline
reflects a significant decline in trading volume in natural gas and natural
gas liquids. PG&E National Energy Group has
focused its trading efforts on asset management, structured transactions and
higher margin trades resulting in a decreaseincreased trading volume. In addition,
increases in trading volumethe price of power and an increasegas in gross profit margin.the second quarter resulted in
increased revenues.
Operating Expenses
- ------------------
Utility operating expenses decreased $15$37 million and $52 million in the
first quarterthree and six month period ended June 30, 2000, respectively, compared to the
similar periods of 2000 to $1.6 billion from first quarter 1999.the prior year.
The tables below summarize the changes in the Utility's operating expenses:
Three months ended June 30, Increase Increase
2000 1999 (Decrease) (Decrease)
-------- -------- -------- --------
(in millions)
Utility operating expenses:
Cost of electric energy $ 975 $ 526 $ 449 85.4%
Cost of gas 182 138 44 31.9%
Operating and maintenance, net 543 608 (65) (10.7)%
Depreciation, amortization and decommissioning 44 509 (465) (91.4)%
-------- -------- -------- --------
Total $ 1,744 $ 1,781 $ (37) (2.1)%
======== ======== ======== ========
Six months ended June 30, Increase Increase
2000 1999 (Decrease) (Decrease)
-------- -------- -------- --------
(in millions)
Utility operating expenses:
Cost of electric energy $ 1,488 $ 935 $ 553 59.1%
Cost of gas 465 384 81 21.1%
Operating and maintenance, net 1,094 1,234 (140) (11.3)%
Depreciation, amortization and decommissioning 345 891 (546) (61.3)%
-------- -------- -------- --------
Total $ 3,392 $ 3,444 $ (52) (1.5)%
======== ======== ======== ========
The decrease in operating expenses is a result of less depreciation expense
because of the sale of 4,289 MW of fossil-fueled and geothermal generation
facilities in the second quarter of 1999. Also contributing to1999 and reduced amortization of
transition costs as a result of increased energy prices, principally in June
of 2000 because of unusually hot weather. To the decreaseextent that current
operating costs, including the cost of electric energy, exceed frozen utility
electric revenues, amortization of transition costs is reduced in operating expenses was aaccordance
with California's transition plan. The decline in operating and maintenance
expense reflectingreflects the impact in 1999 of the Diablo Canyon scheduled refueling
outage with no such scheduledrefueling outage in the first quarterhalf of 2000. These decreases were partially offset by an
increase in theThe cost of
electric energy which experiencedand the cost of gas both priceincreased for the quarter and volumeyear-
to-date over prior year periods because of increases in the first quartervolume of 2000 overpower
and gas purchased and the first quarterprice of 1999.power and gas. High temperatures and
limited supply caused the price increases for power in California in June
2000.
Operating expenses at PG&E National Energy Group declined $318increased $851 million and
$533 million in the second quarter and first quarterhalf of 2000, from $3 billion inrespectively,
compared to the first quartersimilar periods of 1999.the prior year. The decreaseincrease results from
the reducedincreased trading volumes discussed above, increases in the cost control efforts throughout PG&E National Energy Groupof power
and gas, partially offset by reduced depreciation and amortization expense at
PG&E GT-Texas reflective of the write-down to fair value of the PG&E GT-Texas
assets held for sale.
EBITDA
- ------
PG&E Corporation's EBITDA has decreased 33.7 percent and 11.9 percent to $678
million and $1,670 million for the second quarter of 2000 and first half of
2000, respectively. The decrease is principally attributable to the impact of
higher fuel prices at the Utility during the second quarter of 2000. The
Utility accounts for the increased fuel costs through its regulatory balancing
account mechanism, which reduces the amount of amortization of transition
costs.
Income Taxes
- ------------
The effective tax rate for the Corporation has increased to 44.945.0 percent in
the current quarter from 40.6first half of 2000 compared to 40.4 percent in the prior year's first quarterhalf
as a result of: (1) electric industry restructuring which has resulted in the
reversal of temporary tax differences at the Utility whose tax benefits were
originally flowed through to customers causing an increase in income tax
expense independent of pre-tax income and, (2) higher state taxes.
Dividends
- ---------
We base our common stock dividend on a number of financial considerations,
including sustainability, financial flexibility, and competitiveness with
investment opportunities of similar risk. Our current quarterly common stock
dividend is $.30 per common share, which corresponds to an annualized dividend
of $1.20 per common share. We continually review the level of our common
stock dividend, taking into consideration the impact of the changing
regulatory environment throughout the nation, the resolution of asset
dispositions, the operating performance of our business units, and our capital
and financial resources in general.
The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay
PG&E Corporation. During 1999, theThe Utility has been in compliance with its CPUC-authorized
capital structure. PG&E Corporation and the Utility believe that this
requirement will not affect PG&E Corporation's ability to pay common stock
dividends. However, depending on the timing and outcome of the valuation of
the Utility's hydroelectric facilities discussed in "Generation Divestiture"
above, certain valuation methods could necessitate a waiver of the CPUC's
authorized capital structure in order to permit PG&E Corporation or the
Utility to continue paying common stock dividends at the current level. In
addition, a material write-off of net generation-related regulatory assets,
including deferred electric procurement costs, or the Utility's inability to
defer future electric procurement costs, as discussed above, could necessitate
a waiver of the CPUC's authorized capital structure in order to permit PG&E
Corporation or the Utility to continue to pay common stock dividends at the
current level.
LIQUIDITY AND FINANCIAL RESOURCES
Cash Flows from Operating Activities
- ------------------------------------
Net cash provided by PG&E Corporation's operating activities totaled $1,062$1,675
million and $1,025$1,655 million induring the quarterssix months ended March 31,June 30, 2000 and 1999,
respectively. Net cash provided by the Utility's operating activities totaled
$688$1,298 million and $1,092$1,567 million induring the quarterssix months ended March 31,June 30, 2000 and
1999, respectively. High PX prices in June and July 2000 have adversely
impacted the amount of cash generated by the Utility from operations during
these months.
PG&E National Energy Group:
We have entered into tolling agreements with several counterparties giving
PG&E ET the rights to sell electricity generated by facilities owned and
operated by another party. Under such arrangements, PG&E ET supplies the fuel
to the power plant, and then sells the plant's output in the competitive
market. At June 30, 2000, the annual estimated committed payments under such
contracts range from approximately $11 million to $151 million, resulting in
total committed payments over the next 22 years of approximately $2.5 billion.
Cash Flows from Financing Activities
- ------------------------------------
PG&E Corporation:
We fund investing activities from cash provided by operations after capital
requirements and, to the extent necessary, external financing. Our policy is
to finance our investments with a capital structure that minimizes financing
costs, maintains financial flexibility, and, with regard to the Utility,
complies with regulatory guidelines. Based on cash provided from operations
and our investing and disposition activities, we may repurchase equity and
long-term debt in order to manage the overall size and balance of our capital
structure.
During the quartersix-month period ended March 31,June 30, 2000, we issued $10$22 million of
common stock, primarily through the Dividend Reinvestment Plan and the stock
option plan component of the Long-Term Incentive Program. During the quartersix-month
period ended March 31,June 30, 2000, we paid dividends on our common stock of $108$217
million.
During the six-month period ended June 30, 1999, we repurchased $503 million
of our common stock. The 1999 repurchases were executed through accelerated
share repurchase programs. Under the agreement, PG&E Corporation purchased
16.6 million shares of its common stock from a counterparty and entered into a
forward contract with the counterparty. PG&E Corporation retained the risk of
increases and the benefit of decreases in the price of the common shares
purchased by the counterparty. PG&E Corporation had the option to settle its
obligations under the forward contract with either cash or shares of its common
stock. For the three- and six-month periods ended June 30, 1999, this
agreement caused the $0.03 and $0.08 dilution, respectively, reflected in PG&E
Corporation's diluted earnings per share. This dilution was eliminated when
the associated forward contract was settled.
In October 1999, the Board of Directors of PG&E Corporation authorized an
additional $500 million for the purpose of repurchasing shares of the
Corporation's common stock on the open market. This authorization supplements
the approximately $40 million remaining from the amount previously authorized
by the Board of Directors on December 17, 1997. The authorization for share
repurchase extends through September 30, 2001. As of March 31,June 30, 2000, through
our wholly owned subsidiary, we repurchased 7.2 million shares, at a cost of
$159 million under this authorization.
Any open market purchases will be made
by the wholly owned subsidiary of PG&E Corporation.
During the threesix months ended March 31,June 30, 2000, the PG&E National Energy Group
retired $99$130 million of long-term debt.
We maintain a number of credit facilities to support commercial paper
programs, letters of credit, and other short-term liquidity requirements. PG&E
Corporation maintains two $500 million revolving credit facilities, one of
which expires in November 2000 and the other in 2002. These credit facilities
are used to support the commercial paper program and other liquidity needs.
The facility expiring in 2000 may be extended annually for additional one-year
periods upon agreement with the lending institutions. There was $100 million
ofno commercial
paper outstanding at March 31,June 30, 2000. PG&E Corporation introduced a $200 million
Extendible Commercial Note (ECN) program during the third quarter of 1999. The
ECN program supplements our short-term borrowing capability.capability and is not
supported by the credit facilities. There was $98 million ofwere no extendible commercial notes
outstanding at March 31, 2000, which are not supported by the credit facilities.June 30, 2000.
PG&E Gen maintains two $550 million revolving credit facilities. One
facility expires in August 2000 and the other expires in 2003. The total
amount outstanding at March 31,June 30, 2000, backed by the facilities, was $903$907 million
in commercial paper. Of these loans, $550 million is classified as noncurrent
in the Condensed Consolidated Balance Sheet of PG&E Corporation.
In 1998, USGenNE, a subsidiary of PG&E Gen, established a $100 million
revolving credit facility that expires in 2003. As of March 31,June 30, 2000, there is
no outstanding balance on this facility.
PG&E GT NW maintains a $100 million revolving credit facility that expires
in 2002, but has an annual renewal option allowing the facility to maintain a
three-year duration. PG&E GT NW also maintains a $50 million 364-day credit
facility that expires in 2000,2001, but can be extended for successive 364-day
periods. At March 31,June 30, 2000, PG&E GT NW had an outstanding commercial paper
balance of $64$40 million, which is classified as noncurrent in the Condensed
Consolidated Balance Sheet of PG&E Corporation.
PG&E GTT maintains four separate credit facilities that total $250 million
and are guaranteed by PG&E Corporation. At March 31,June 30, 2000, PG&E GTT had $192$180
million of outstanding short-term bank borrowings related to these credit
facilities. These lines may be cancelled upon demand and bear interest at each
respective bank's quoted money market rate. The borrowings are unsecured and
unrestricted as to use.
Utility:
During the threesix months ended March 31,June 30, 2000, the Utility paid dividends on its
common stock of $122$250 million. In April 2000, the Utility repurchased from PG&E
Corporation 11.9 million shares of its common stock at a cost of $275 million.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during the threesix months ended March 31,June 30, 2000, totaled $102$216 million.
Of this amount, $73$139 million related to the Utility's rate reduction bonds
maturing, and $27$77 million related to the maturities and redemption of various of the Utility's
medium-term notes and other debt.
The Utility maintains a $1 billion revolving credit facility, which expires
in 2002. The Utility may extend the facility annually for additional one-year
periods upon agreement with the banks. This facility is used to support the
Utility's commercial paper program and other liquidity requirements. The total
amount outstanding at March 31,June 30, 2000, backed by this facility, was $209$480 million
in commercial paper. If the high PX prices, experienced in June and July 2000,
were to continue through the transition period, the Utility would be required to
further draw on this facility during that time frame to meet its liquidity
requirements.
Cash Flows from Investing Activities
- ------------------------------------
Utility:
The primary uses of cash for investing activities are additions to property,
plant, and equipment, unregulated investments in partnerships, and
acquisitions.
The Utility's estimated capital spending for 2000 is approximately $1.3
billion, excluding capital expenditures for divested fossil and geothermal
power plants. The Utility's capital expenditures for the threesix months ended March 31,June
30, 2000, was $265$572 million.
PG&E National Energy Group:
PG&E Gen is associated with the construction of threeThree natural gas-fueled combined-cycle power plants.plants are currently under
construction which when completed will be owned or leased by PG&E National
Energy Group. These power plants, referred to as "merchant power plants," will
sell power as a commodity in the competitive marketplace. The electricity
generated by these plants will be sold on a wholesale basis to local utilities
and power marketers, including PG&E ET, which, in turn, will sell it to
industrial, commercial, and other electricity customers.
Millennium Power, a 360-MW power plant located in Massachusetts, is scheduledexpected
to begin commercial service in the firstlast quarter of 2001.2000. Lake Road Generating
Plant (Lake Road), an approximately 790-MW power plant located in Connecticut,
is scheduledexpected to begin commercial service in 2001. La Paloma Generating Plant
(La Paloma), an approximately 1,050-MW power plant is located in California, and is
scheduledexpected to begin commercial service in 2001.2002. During the second quarter
critical environmental permits were obtained for the Athens Generating Plant, a
1,080-MW power plant located in New York, and the 1,000 MW Harquahala
generating project located in Arizona. Both plants are expected to begin
commercial service in 2003.
Lake Road and La Paloma are being financed through synthetic leases with a
third partythird-party owner. PG&E GenNational Energy Group will operate the plants under
operating leases. The estimated cost to construct these plants is
approximately $1.4 billion.
PG&E GenNational Energy Group broke ground for the Madison Wind Power Project
in New York in April 2000. This 11.5 MW project will be the largest wind
generating facility in the Eastern United States and is expected to be
operational in September 2000. The estimated cost to construct this plant is
$16 million.
USGenNEIn addition to the above projects under construction, PG&E National Energy
Group has proposed an emission reduction plan which may include a $400
million modernizationadditional 7,000 to 10,000 MW in development for commercial
operation in the next five years. The completion of its 760-MW coal-fired power plant in Salem,
Massachusetts. The proposed modernization will use advanced technologiesthese projects is subject
to many factors, including but not limited to various regulatory and
environmental approvals, adequate financing on satisfactory terms, competitive
conditions including the expansion and retirement plans of others, market
prices for emissions removal, with construction beginning in 2002electricity, future fuel prices, delays by third party contractors,
and ending by January
2004.the unavailability of required equipment.
ENVIRONMENTAL MATTERS
We are subject to laws and regulations established to both maintain and
improve the quality of the environment. Where our properties contain hazardous
substances, these laws and regulations require us to remove those substances or
remedy effects on the environment. At March 31, 2000, the Utility has accrued $275 million ($303 million on an
undiscounted basis) for clean-up costs at identified sites. If other
responsible parties fail to pay or expected outcomes change, then these costs
may be as much as $501 million. Of the $275 million, the Utility has recovered
$148 million through rates, including $34 million through depreciation and
expects to recover another $99 million in future rates. Additionally, the
Utility mitigates its cost by seeking recovery from insurance carriers and
other third parties. (See Note 6 of Notes to Condensed
Consolidated Financial Statements.)
The costStatement for further discussion of the hazardous substance remediation ultimately undertaken by the
Utility is difficult to estimate. A change in the estimate may occur in the
near term due to uncertainty concerning the Utility's responsibility, the
complexity of environmental laws and regulations, and the selection of
compliance alternatives. The Utility estimates the upper limit of the range
using assumptions least favorable to the Utility, based upon a range of
reasonably possible outcomes. Costs may be higher if the Utility is found to
be responsible for clean-up costs at additional sites or expected outcomes
change.
In addition to the potential $400 million modernization of the coal-fired
power plant located on Salem Harbor in Salem, Massachusetts, USGenNE also is
studying various modernization alternatives for its 1,586 MW coal-fired
Brayton Point power plant in Somerset, Massachusetts. On April 18, 2000 the
Conservation Law Foundation (CLF) served various PG&E Gen affiliates,
including USGenNE, a notice of its intent to file suit under the citizen suit
provision of the Resource Conservation Recovery Act. CLF stated in such
notice that it plans in its suit to allege that the PG&E Gen affiliates,
generator of fossil fuel combustion wastes, has and is contributing to the
past and present handling, storage, treatment and disposal of such wastes at
the Salem Harbor and Brayton Point power plants which may present an imminent
and substantial endangerment to health or the environment. It further stated
it will allege that PG&E Gen's management practices in connection with such
wastes has resulted in severe groundwater contamination at both facilities.
CLF has stated that it intends to seek an order requiring all necessary
measures be taken to halt what it characterizes as the endangerment of health
and environment. At this preliminary stage, we are unable to determine
whether the ultimate outcome of this matter would have a material adverse
effect on our results of operations or financial condition.these matters.)
RISK MANAGEMENT ACTIVITIES
We have established a risk management policy that allows derivatives to be
used for both hedging and non-hedging purposes (a derivative is a contract
whose value is dependent on or derived from the value of some underlying
asset). We use derivatives for hedging purposes primarily to offset underlying
commodity price risks. We also participate in markets using derivatives to
gather market intelligence, create liquidity, and maintain a market presence.
Such derivatives include forward contracts, futures, swaps, and options. Net
open positions often exist or are established due to PG&E Corporation's
assessment of its response to changing market conditions. To the extent that
PG&E Corporation has an open position, it is exposed to the risk that
fluctuating market prices may adversely impact its financial results. Our risk
management policy and the trading and risk management policies of our
subsidiaries prohibit the use of derivatives whose payment formula includes a
multiple of some underlying asset.
We prepare a daily assessment of our portfolio market risk exposure using
value-at-risk and other methodologies that simulate future price movements in
the energy markets to estimate the size and probability of future potential
losses. The quantification of market risk using value-at-risk provides a
consistent measure of risk across diverse energy markets and products. The use
of this methodology requires a number of important assumptions, including the
selection of a confidence level for losses, volatility of prices, market
liquidity, and a holding period. PG&E Corporation's daily value-at-risk for
commodity price sensitive derivative instruments as of March 31,June 30, 2000, was $1.6$5.6
million for trading activities and $0.3$5.7 million for non-trading activities.
Value-at-risk has several limitations as a measure of portfolio risk,
including, but not limited to, underestimation of the risk of a portfolio with
significant options exposure, inadequate indication of the exposure of a
portfolio to extreme price movements, and the inability to address the risk
resulting from intra-day trading activities.
In June 1999, the Financial Accounting Standards Board (FASB) issuedPG&E Corporation expects to adopt Statement of Financial Accounting
Standards (SFAS) No. 137, "Accounting for
Derivative Instruments and Hedging Activities-Deferral of the Effective Date of
FASB Statement No. 133," which delayed the implementation of as amended by SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," by one year to
require adoption in years beginning after June 15, 2000. The Statement permits
early adoption as of the beginning of any fiscal quarter.
PG&E Corporation expects to adopt SFAS No. 133138, no later than January 1,
2001. The Statement will require us to recognize all derivatives, as defined
in the Statement, on the balance sheet at fair value. Derivatives, or any
portion thereof, that are not effective hedges must be adjusted to fair value
through income. If derivatives are effective hedges, depending on the nature
of the hedges, changes in the fair value of derivatives either will be offset
against the change in fair value of the hedged assets, liabilities, or firm
commitments through earnings, or will be recognized in other comprehensive
income until the hedged items are recognized in earnings. We currently are
evaluating what the effect of SFAS No. 133 will be on the earnings and
financial position of PG&E Corporation. However, we already use the mark-to-marketmark-to-
market method of accounting for our commodity non-hedging and risk management
activities.
LEGAL MATTERS
In the normal course of business, both the Utility and PG&E Corporation
are named as parties in a number of claims and lawsuits. (See Note 56 of
Notes to Condensed Consolidated Financial Statements for further discussion
of significant pending legal matters.)
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- -------------------------------------------------------------------
PG&E Corporation's and Pacific Gas and Electric Company's primary market risk
results from changes in energy prices and interest rates. We engage in price
risk management activities for both non-hedging and hedging purposes.
Additionally, we may engage in hedging activities using futures, options, and
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies. (See Risk Management Activities,
above.)
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
-----------------
Moss Landing Power Plant
In December 1999, the Utility was notified by the purchaserFor a description of its former
Moss Landing power plant that it had identified a cleaning procedure used
at the plant that released heated water and organic debris from the intake,
and that this procedure is not specified in the plant's National Pollutant
Discharge Elimination System (NPDES) permit issued by the Central Coast
Regional Water Quality Control Board (Central Coast Board). The purchaser
notified the Central Coast Board of its findings and the Central Coast
Board requested additional information from the purchaser. The Utility
initiated an investigation of these activities during the time it owned the
plant. The Utility notified the Central Coast Board that it had undertaken
an investigation and that it would present the results to the Central Coast
Board when the investigation was completed. On March 15, 2000, the Central
Coast Board sent a letter to the Utility requesting specific information
regarding the "backflush" procedure used at Moss Landing. The Utility
completed its investigation and provided the requested information to the
Central Coast Board on April 7, 2000. Until the resultsmaterial legal proceedings, see Note 6 of the Utility's
investigation are discussed with the Central Coast Board, it is not
possible to determine whether the Utility will suffer a loss in connection
with this matter or to provide a more detailed estimate of such liability.
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
PG&E Corporation:
On April 19, 2000, PG&E
Corporation held its annual meeting of
shareholders. At that meeting, the shareholders voted as indicated below
on the following matters:
1. Election of the following directors to serve until the next annual
meeting of shareholders or until their successors are elected and
qualified:
For Withheld
---------- ----------
Richard A. Clarke 252,017,302 9,890,523
Harry M. Conger 252,942,092 8,965,733
David A. Coulter 252,110,956 9,796,869
C. Lee Cox 253,040,357 8,867,468
William S. Davila 253,036,334 8,871,491
Robert D. Glynn, Jr. 252,909,447 8,998,378
David M. Lawrence, MD 252,705,855 9,201,970
Mary S. Metz 252,995,318 8,912,507
Carl E. Reichardt 252,790,649 9,117,176
John C. Sawhill 253,084,819 8,823,006
Barry Lawson Williams 252,723,645 9,184,180
2. Ratification of the appointment of Deloitte & Touche LLP as
independent public accountants for 2000:
For: 256,379,276
Against: 2,506,940
Abstain: 3,021,609
The proposal was approved by a majority of the shares present and voting
(including abstentions) which shares voting affirmatively also constituted
a majority of the required quorum.
3. Management proposal regarding proposed amendments to PG&E
Corporation's Articles of Incorporation to implement the elimination
of a supermajority vote provision.
For: 206,193,826
Against: 10,349,714
Abstain: 5,261,226
Broker non-vote:(1) 40,103,059
The proposal was approved by a majority of the outstanding shares.
4. Management proposal regarding proposed amendment to PG&E Corporation's
Articles of Incorporation to decrease the authorized minimum and
maximum number of directors:
For: 250,306,476
Against: 6,974,397
Abstain: 4,626,543
Broker non-vote:(1) 409
The proposal was approved by a majority of the outstanding shares.
5. Consideration of a shareholder proposal to appoint independent
directors to key Board committees:
For: 95,827,965
Against: 115,539,858
Abstain: 10,431,336
Broker non-votes:(1) 40,108,666
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
6. Consideration of a shareholder proposal regarding confidential
shareholder voting:
For: 108,057,613
Against: 106,010,434
Abstain: 7,730,522
Broker non-votes:(1) 40,109,256
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
- ---------------
(1) A non-vote occurs when a broker or other nominee holding shares for a
beneficial owner indicates a vote on one or more proposals, but does not
indicate a vote on other proposals because the broker or other nominee does
not have discretionary voting power as to such proposals and has not received
voting instructions from the beneficial owner as to such proposals.
7. Consideration of a shareholder proposal regarding the treatment of
abstentions:
For: 30,290,100
Against: 180,368,498
Abstain: 11,173,674
Broker non-votes:(1) 40,075,553
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
8. Consideration of a shareholder proposal regarding cumulative voting:
For: 72,824,979
Against: 135,858,343
Abstain: 13,115,837
Broker non-votes:(1) 40,108,666
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
9. Consideration of a shareholder proposal regarding compensation of
directors in stock:
For: 28,219,661
Against: 183,248,630
Abstain: 10,330,868
Broker non-votes:(1) 40,108,666
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
10. Consideration of a proposal regarding severance benefits received
during mergers or acquisitions:
For: 36,508,116
Against: 176,996,783
Abstain: 8,294,260
Broker non-votes:(1) 40,108,666
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
- ---------------
(1) A non-vote occurs when a broker or other nominee holding shares for a
beneficial owner indicates a vote on one or more proposals, but does not
indicate a vote on other proposals because the broker or other nominee does
not have discretionary voting power as to such proposals and has not received
voting instructions from the beneficial owner as to such proposals.
Pacific Gas and Electric Company:
On April 19, 2000, Pacific Gas and Electric Company held its annual meeting
of shareholders. Shares of capital stock ofNotes to Condensed
Consolidated Financial Statements under Part I, Item 1 above, as well as
the Annual Report on Form 10-K filed by PG&E Corporation and Pacific Gas
and Electric Company consist of shares of common stockfor the year ended December 31, 1999, and shares of first preferred
stock. Asthe
Quarterly Report on Form 10-Q filed by PG&E Corporation and a subsidiary own all of the outstanding
shares of common stock, they hold approximately 95% of the combined voting
power of the outstanding capital stock of Pacific Gas and
Electric Company.
PG&E Corporation and the subsidiary voted all of their respective shares of
common stockCompany for the nominees named in the joint proxy statement and for
the ratification of the appointment of Deloitte & Touche LLP as independent
public accountants forquarter ended March 31, 2000. The balance of the votes shown below were cast
by holders of shares of first preferred stock. At the annual meeting, the
shareholders voted as indicated below on the following matters:
1. Election of the following directors to serve until the next annual
meeting of shareholders or until their successors are elected and
qualified:
For Withheld
----------- -----------
Richard A. Clarke 338,548,826 187,097
Harry M. Conger 338,566,995 168,928
David A. Coulter 338,547,768 188,155
C. Lee Cox 338,570,513 165,410
William S. Davila 338,567,649 168,274
Robert D. Glynn, Jr. 338,559,318 176,605
David M. Lawrence, MD 338,556,908 179,015
Mary S. Metz 338,563,724 172,199
Carl E. Reichardt 338,551,976 183,947
John C. Sawhill 338,569,718 166,205
Gordon R. Smith 338,561,480 174,443
Barry Lawson Williams 338,566,195 169,728
2. Ratification of the appointment of Deloitte & Touche LLP as
independent public accountants for 2000:
For: 338,539,587
Against: 47,602
Abstain: 148,734
Item 5. Other Information
-----------------
A. 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
threesix months ended March 31,June 30, 2000, was 3.89.3.81. Pacific Gas and Electric
Company's earnings to combined fixed charges and preferred stock dividends
ratio for the threesix months ended March 31,June 30, 2000, was 3.67.3.60. 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.
B. Amendment to Bylaws of Pacific Gas and Electric Company
On June 21, 2000, the Board of Directors of Pacific Gas and Electric
Company approved amendments to Pacific Gas and Electric Company's Bylaws to
require a shareholder to give advance notice to the Company of director
nominations and other proposals that the shareholder intends to present for
action at shareholder meetings. The amended Bylaws are filed as an exhibit
to this report. Under amended Article I, Section 2 of the Bylaws, notice
of director nominations and proposals intended to be presented by
shareholders at the annual meeting of shareholders to be held on
April 18, 2001, assuming the matter is a proper matter for
shareholder action, must be received by the Corporate Secretary by
January 27, 2001. As mentioned in the 2000 joint proxy statement of
PG&E Corporation and Pacific Gas and Electric Company, shareholders
who wish to have their proposal considered for inclusion in the 2001
joint proxy statement in accordance with Securities and Exchange
Commission Rule 14a-8 must submit their proposal to the Corporate
Secretary no later than November 13, 2000.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 3.1 Restated Articles of Incorporation of PG&E Corporation,
dated as of May 5, 2000
Exhibit 3.2 Bylaws of PG&E Corporation, dated as of May 5,June 21, 2000
Exhibit 10 Letter Regarding Relocation Arrangements Between PG&E
Corporation3.2 Bylaws of Pacific Gas and Thomas B. KingElectric Company, dated as
of June 21, 2000
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
Exhibit 27.1 Financial Data Schedule for the quarter ended
March 31,June 30, 2000, for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
March 31,June 30, 2000, for Pacific Gas and Electric
Company
(b) The following Current Reports on Form 8-K were filed during the firstsecond
quarter of 2000 and through the date hereof (2):
1. January 21,April 14, 2000
Item 5. Other Events
A. Pacific Gas and Electric Company's General Rate Case2000 Cost of Capital
Proceeding
B. Proposed Auction2. June 8, 2000
Item 5. Other Events
Pacific Gas and Electric Company's 2000 Cost of Capital
Proceeding
3. June 14, 2000
Item 5. Other Events
Valuation and Disposition of Pacific Gas and Electric
Company's Hydroelectric Generating Assets.
C. 1998 Annual Transition Cost ProceedingGeneration Assets
4. July 28, 2000
Item 5. Other Events
Pacific Gas and Electric Company's 2001 Attrition Rate
Adjustment Application
- ---------------
(2) Unless otherwise noted, all Current Reports on Form 8-K were filed
under both Commission File Number 1-12609 (PG&E Corporation) and
Commission File Number 1-2348 (Pacific Gas and Electric Company).
2. January 31, 2000
Item 5. Other Events
Sale of Texas Gas Transmission Companies
3. February 23, 2000
Item 5. Other Events
A. Pacific Gas and Electric Company's General Rate Case
Proceeding
B. 1998 Annual Transition Cost Proceeding
C. Disposition of PG&E Energy Services Corporation
4. April 14, 2000
Item 5. Other Events
A. Pacific Gas and Electric Company's 2000 Cost of Capital
Proceeding
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by
the undersigned thereunto duly authorized.
PG&E CORPORATION
CHRISTOPHER P. JOHNS
By __________________________
CHRISTOPHER P. JOHNS
Vice President and Controller
PACIFIC GAS AND ELECTRIC COMPANY
KENT M. HARVEY
By __________________________
KENT M. HARVEY
Senior Vice President-Chief Financial
Officer, Controller and Treasurer
Dated: May 12,August 2, 2000
Exhibit Index
Exhibit No. Description of Exhibit
Exhibit 3.1 Restated Articles of Incorporation of PG&E
Corporation, dated as of May 5, 2000
Exhibit 3.2 Bylaws of PG&E Corporation, dated as of May 5,June 21, 2000
Exhibit 10 Letter Regarding Relocation Arrangements Between PG&E
Corporation3.2 Bylaws of Pacific Gas and Thomas B. King
ExhibitElectric Company, dated as
of June 21, 2000
11 Computation of Earnings Per Common Share
Exhibit
12.1 Computation of Ratio of Earnings to Fixed Charges for
Pacific Gas and Electric Company
Exhibit
12.2 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas
and Electric Company
Exhibit 27.1 Financial Data Schedule for the quarter ended
March 31,June 30, 2000 for PG&E Corporation
Exhibit
27.2 Financial Data Schedule for the quarter ended
March 31,June 30, 2000 for Pacific Gas and Electric Company