FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
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(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1997
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
77 Beale Street, P.O. Box 770000, San Francisco, California 94177
- ------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrants' telephone number, including area code:(415) 973-7000
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 August 5, 1997:
PG&E Corporation 395,112,240 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
<PAGE>
PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1997
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME........................1
BALANCE SHEET...........................................2
STATEMENT OF CASH FLOWS ................................3
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME........................4
BALANCE SHEET...........................................5
STATEMENT OF CASH FLOWS.................................6
NOTE 1: GENERAL...........................................7
NOTE 2: ELECTRIC INDUSTRY RESTRUCTURING...................9
NOTE 3: NATURAL GAS MATTERS..............................13
NOTE 4: PG&E OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY PG&E SUBORDINATED DEBENTURES..............13
NOTE 5: COMMITMENTS AND CONTINGENCIES....................14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.......................16
COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........17
ELECTRIC INDUSTRY RESTRUCTURING...........................18
Transition Cost Recovery...............................18
Competitive Market Framework...........................21
Accounting for the Effects of Regulation...............22
GAS INDUSTRY RESTRUCTURING................................23
ACQUISITIONS AND SALES....................................24
RESULTS OF OPERATIONS.....................................26
Common Stock Dividend..................................27
Earnings Per Common Share..............................27
Utility................................................27
Other Lines of Business................................27
LIQUIDITY AND CAPITAL RESOURCES
Sources of Capital.....................................28
Cost of Capital Application............................29
Environmental Matters..................................29
Legal Matters..........................................29
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.........................................30
ITEM 5. OTHER INFORMATION.........................................32
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................32
SIGNATURE..........................................................34
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME
(in thousands, except per share amounts)
<CAPTION>
Three months ended June 30, Six months ended June 30,
1997 1996 1997 1996
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Operating Revenues
Electric and gas utility $ 2,278,764 $ 2,059,845 $ 4,552,742 $ 4,224,460
Energy trading 680,576 - 1,663,124 -
Other 123,566 78,821 232,534 162,974
----------- ------------ ------------ -----------
Total operating revenues 3,082,906 2,138,666 6,448,400 4,387,434
Operating Expenses
Cost of electric energy 632,544 530,792 1,169,014 997,786
Cost of gas 761,685 67,151 1,967,040 255,288
Maintenance and other operating 571,243 525,058 1,019,723 981,532
Depreciation and decommissioning 465,687 303,382 924,803 606,329
Administrative and general 200,324 346,762 370,282 526,141
Property and other taxes 80,580 77,146 162,941 158,589
----------- ----------- ----------- -----------
Total operating expenses 2,712,063 1,850,291 5,613,803 3,525,665
----------- ----------- ----------- -----------
Operating Income 370,843 288,375 834,597 861,769
Interest income 12,190 21,348 25,154 45,691
Interest expense (164,255) (157,458) (322,195) (327,018)
Other income 71,658 7,268 84,366 11,339
Preferred dividend requirement and
redemption premium (8,278) (8,278) (16,556) (16,556)
----------- ----------- ----------- -----------
Pretax Income 282,158 151,255 605,366 575,225
Income Taxes 89,253 47,753 239,957 219,297
----------- ----------- ----------- -----------
Earnings Available for Common Stock $ 192,905 $ 103,502 $ 365,409 $ 355,928
=========== =========== =========== ===========
Weighted Average Common Shares
Outstanding 397,677 415,125 403,072 414,738
Earnings Per Common Share $.49 $.25 $.91 $.86
Dividends Declared Per Common Share $.30 $.49 $.60 $.98
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
BALANCE SHEET
(in thousands)
<CAPTION>
Balance at
June 30, December 31,
1997 1996
------------- -------------
<S> <C> <C>
ASSETS
Plant in Service
Electric $ 25,239,420 $ 24,757,479
Gas 6,765,301 6,558,413
Gas transmission 1,829,002 1,579,693
------------- -------------
Total plant in service (at original cost) 33,833,723 32,895,585
Accumulated depreciation and decommissioning (15,233,682) (14,301,934)
------------- -------------
Net plant in service 18,600,041 18,593,651
Construction Work in Progress 478,447 414,229
Other Noncurrent Assets
Nuclear decommissioning funds 940,061 882,929
Investment in nonregulated projects 773,115 817,259
Other assets 306,496 134,271
------------ ------------
Total other noncurrent assets 2,019,672 1,834,459
Current Assets
Cash and cash equivalents 207,188 143,402
Accounts receivable, net 1,170,130 1,151,844
Commodity contracts accounts receivable 355,974 387,342
Regulatory balancing accounts receivable 625,271 444,156
Inventories 513,130 530,085
Prepayments 67,483 54,116
------------ ------------
Total current assets 2,939,176 2,710,945
Deferred Charges
Income tax-related deferred charges 1,060,061 1,133,043
Other deferred charges 1,577,541 1,550,789
------------ ------------
Total deferred charges 2,637,602 2,683,832
------------ ------------
TOTAL ASSETS $ 26,674,938 $ 26,237,116
============= =============
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock equity $ 8,248,770 $ 8,363,301
Preferred stock without mandatory redemption provisions 390,591 402,056
Preferred stock with mandatory redemption provisions 137,500 137,500
Company obligated mandatorily redeemable preferred
securities of trust holding solely PG&E subordinated
debentures 300,000 300,000
Long-term debt 7,661,892 7,770,067
------------- -------------
Total capitalization 16,738,753 16,972,924
Current Liabilities
Short-term borrowings 1,529,002 680,900
Current portion of long-term debt 26,716 209,867
Accounts payable
Commodity contracts 372,744 388,369
Trade creditors 436,886 489,527
Other 387,180 361,258
Accrued taxes 425,224 310,271
Amounts due customers 150,465 186,899
Deferred income taxes 208,308 157,064
Interest payable 55,266 63,193
Dividends payable 128,264 123,310
Other 332,844 309,104
------------- -------------
Total current liabilities 4,052,899 3,279,762
Deferred Credits and Other
Noncurrent Liabilities
Deferred income taxes 3,785,899 3,941,435
Deferred tax credits 360,277 379,563
Noncurrent balancing account liabilities 149,546 120,858
Other 1,587,564 1,542,574
------------- -------------
Total deferred credits and other noncurrent liabilities 5,883,286 5,984,430
Commitments and Contingencies (Notes 2, 3, and 5) - -
------------- -------------
TOTAL CAPITALIZATION AND LIABILITIES $ 26,674,938 $ 26,237,116
============= =============
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
STATEMENT OF CASH FLOWS
(in thousands)
<CAPTION>
For the six months ended June 30, 1997 1996
----------- -----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 365,409 $ 355,928
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and decommissioning 924,803 606,329
Amortization 60,383 44,774
Deferred income taxes and tax credits-net (105,997) (18,532)
Other deferred charges (77,257) 56,185
Other noncurrent liabilities (48,233) 9,035
Noncurrent balancing account liabilities and
other deferred credits 127,752 (42,224)
Gain on sale of International Generating Company, Ltd. (110,000) -
Net effect of changes in operating assets
and liabilities:
Accounts receivable 92,452 84,135
Regulatory balancing accounts receivable (41,341) 18,216
Inventories (2,669) 33,191
Accounts payable (128,508) (57,170)
Accrued taxes 114,953 129,230
Other working capital (174,726) 119,581
Other-net 140,758 51,865
----------- -----------
Net cash provided by operating activities 1,137,779 1,390,543
----------- -----------
Cash Flows From Investing Activities
Capital expenditures (769,916) (513,109)
Investments in nonregulated projects (96,969) 11,596
Acquisition of Teco Pipeline Company (40,668) -
Proceeds from sale of International Generating Company, Ltd. 137,088 -
Other-net (32,115) (40,644)
----------- -----------
Net cash used by investing activities (802,580) (542,157)
----------- -----------
Cash Flows From Financing Activities
Common stock issued 26,911 113,290
Common stock repurchased (574,862) (135,036)
Long-term debt issued 50,006 983,944
Long-term debt matured, redeemed, or repurchased-net (344,521) (1,196,269)
Short-term debt issued (redeemed)-net 848,102 (773,874)
Dividends paid (261,634) (422,994)
Other-net (15,415) (14,285)
----------- -----------
Net cash used by financing activities (271,413) (1,445,224)
----------- -----------
Net Change in Cash and Cash Equivalents 63,786 (596,838)
Cash and Cash Equivalents at January 1 143,402 734,295
----------- -----------
Cash and Cash Equivalents at June 30 $ 207,188 $ 137,457
=========== ===========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 314,523 $ 306,442
Income taxes 237,245 106,119
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(in thousands, except per share amounts)
<CAPTION>
Three months ended June 30, Six months ended June 30,
1997 1996 1997 1996
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Operating Revenues
Electric $ 1,876,388 $ 1,660,867 $ 3,598,394 $ 3,309,469
Gas 402,376 398,978 954,348 914,991
Other - 78,821 - 162,974
------------ ------------ ------------ ------------
Total operating revenues 2,278,764 2,138,666 4,552,742 4,387,434
Operating Expenses
Cost of electric energy 597,058 530,792 1,107,176 997,786
Cost of gas 61,681 67,151 276,136 255,288
Maintenance and other operating 560,642 525,058 1,005,849 981,532
Depreciation and decommissioning 447,954 303,382 890,479 606,329
Administrative and general 163,712 346,762 301,112 526,141
Property and other taxes 77,450 77,146 156,479 158,589
------------ ------------ ------------ ------------
Total operating expenses 1,908,497 1,850,291 3,737,231 3,525,665
------------- ------------ ------------ ------------
Operating Income 370,267 288,375 815,511 861,769
Interest income 11,113 21,348 21,517 45,691
Interest expense (146,791) (157,458) (290,833) (327,018)
Other income 2,447 7,268 1,379 11,339
------------ ------------ ------------ ------------
Pretax Income 237,036 159,533 547,574 591,781
Income Taxes 107,148 47,753 245,107 219,297
------------ ------------ ------------ ------------
Net Income 129,888 111,780 302,467 372,484
Preferred dividend requirement and
redemption premium (8,278) (8,278) (16,556) (16,556)
------------- ----------- ------------ ------------
Earnings Available for Common Stock $ 121,610 $ 103,502 $ 285,911 $ 355,928
============ =========== ============ ============
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
BALANCE SHEET
(in thousands)
<CAPTION>
Balance at June 30, December 31,
1997 1996
------------ ------------
<S> <C> <C>
ASSETS
Plant in Service
Electric $ 25,225,536 $ 24,757,479
Gas 6,753,293 8,138,106
------------- -------------
Total plant in service (at original cost) 31,978,829 32,895,585
Accumulated depreciation and decommissioning (14,786,214) (14,301,934)
------------- -------------
Net plant in service 17,192,615 18,593,651
Construction Work in Progress 454,659 414,229
Other Noncurrent Assets
Nuclear decommissioning funds 940,061 882,929
Investment in nonregulated projects - 817,259
Other assets 101,401 134,271
------------- ------------
Total other noncurrent assets 1,041,462 1,834,459
Current Assets
Cash and cash equivalents 70,098 143,402
Accounts receivable, net 1,080,683 1,151,844
Commodity contracts accounts receivable - 387,342
Regulatory balancing accounts receivable 625,271 444,156
Inventories 497,929 530,085
Prepayments 30,759 54,116
------------- ------------
Total current assets 2,304,740 2,710,945
Deferred Charges
Income tax-related deferred charges 1,034,355 1,133,043
Other deferred charges 1,503,589 1,550,789
------------- ------------
Total deferred charges 2,537,944 2,683,832
------------- -------------
TOTAL ASSETS $ 23,531,420 $ 26,237,116
============= =============
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock equity $ 7,101,171 $ 8,363,301
Preferred stock without mandatory redemption provisions 402,056 402,056
Preferred stock with mandatory redemption provisions 137,500 137,500
Company obligated mandatorily redeemable preferred
securities of trust holding solely PG&E subordinated
debentures 300,000 300,000
Long-term debt 6,984,006 7,770,067
------------ ------------
Total capitalization 14,924,733 16,972,924
Current Liabilities
Short-term borrowings 1,178,064 680,900
Current portion of long-term debt 23,645 209,867
Accounts payable
Commodity contracts - 388,369
Trade creditors 395,769 489,527
Other 581,810 361,258
Accrued taxes 404,882 310,271
Amounts due customers 150,465 186,899
Deferred income taxes 208,308 157,064
Interest payable 49,467 63,193
Dividends payable 8,314 123,310
Other 292,623 309,104
------------- ------------
Total current liabilities 3,293,347 3,279,762
Deferred Credits and Other
Noncurrent Liabilities
Deferred income taxes 3,346,743 3,941,435
Deferred tax credits 359,943 379,563
Noncurrent balancing account liabilities 149,546 120,858
Other 1,457,108 1,542,574
------------ ------------
Total deferred credits and other noncurrent liabilities 5,313,340 5,984,430
Commitments and Contingencies (Notes 2, 3, and 5) - -
------------- -------------
TOTAL CAPITALIZATION AND LIABILITIES $ 23,531,420 $ 26,237,116
============= =============
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(in thousands)
<CAPTION>
For the six months ended June 30, 1997 1996
------------ -----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 302,467 $ 372,484
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and decommissioning 890,479 606,329
Amortization 58,873 44,774
Deferred income taxes and tax credits-net (110,913) (18,532)
Other deferred charges (66,769) 56,185
Other noncurrent liabilities (41,637) 9,035
Noncurrent balancing account liabilities and
other deferred credits 133,678 (42,224)
Net effect of changes in operating assets
and liabilities:
Accounts receivable 378 84,135
Regulatory balancing accounts receivable (41,341) 18,216
Inventories (673) 33,191
Accounts payable (154,765) (57,170)
Accrued taxes 113,164 129,230
Other working capital (168,225) 119,581
Other-net 13,306 35,309
------------ ------------
Net cash provided by operating activities 928,022 1,390,543
------------ ------------
Cash Flows From Investing Activities
Capital expenditures (742,848) (513,109)
Investments in nonregulated projects - 11,596
Other-net (113,701) (40,644)
------------ ------------
Net cash used by investing activities (856,549) (542,157)
------------ ------------
Cash Flows From Financing Activities
Long-term debt issued 43,506 983,944
Long-term debt matured, redeemed, or repurchased-net (315,882) (1,196,269)
Short-term debt issued (redeemed)-net 497,164 (773,874)
Dividends paid (361,489) (422,994)
Other-net (8,076) (36,031)
----------- -----------
Net cash used by financing activities (144,777) (1,445,224)
----------- -----------
Net Change in Cash and Cash Equivalents (73,304) (596,838)
Cash and Cash Equivalents at January 1 143,402 734,295
----------- -----------
Cash and Cash Equivalents at June 30 $ 70,098 $ 137,457
=========== ===========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 277,059 $ 306,442
Income taxes 242,748 106,119
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: GENERAL
Holding Company Formation:
- -------------------------
Effective January 1, 1997, Pacific Gas and Electric Company (PG&E) became a
subsidiary of its new parent holding company, PG&E Corporation. PG&E's
ownership interest in Pacific Gas Transmission Company (PGT) and PG&E
Enterprises (Enterprises) was transferred to PG&E Corporation. PG&E's
outstanding common stock was converted on a share-for-share basis into PG&E
Corporation's outstanding common stock. PG&E's debt securities and
preferred stock were unaffected and remain securities of PG&E.
Basis of Presentation:
- ----------------------
This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation
and PG&E. PG&E Corporation's consolidated financial statements include the
accounts of PG&E Corporation, PG&E, PG&E Gas Transmission Corporation
including PGT, PG&E Energy Trading Corporation, PG&E Energy Services
Corporation, and Enterprises, as well as the accounts of their wholly owned
and controlled subsidiaries (collectively, the Corporation). PG&E's
consolidated financial statements include the accounts of PG&E and its
wholly owned and controlled subsidiaries. Because PGT and Enterprises were
wholly owned and controlled subsidiaries of PG&E during 1996, they are
included in PG&E's 1996 consolidated financial statements.
The "Notes to Consolidated Financial Statements" herein pertain to the
Corporation and PG&E. Currently, PG&E'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 PG&E's
Consolidated Financial Statements and Notes to Consolidated Financial
Statements incorporated by reference in their combined 1996 Annual Report on
Form 10-K.
In the opinion of management, the accompanying statements reflect all
adjustments that are necessary to present a fair statement of the
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. Certain amounts in the prior year's
consolidated financial statements have been reclassified to conform to the
1997 presentation. Results of operations for interim periods are not
necessarily indicative of results to be expected for a full year.
Accounting for Derivative Instruments (Derivatives):
- ----------------------------------------------------
Effective June 30, 1997, the Corporation adopted Securities and Exchange
Commission (SEC) amended Rule 4-08 of Regulation S-X, General Notes to the
Financial Statements, which modifies the disclosure of accounting policies
for certain derivative instruments.
The Corporation engages in price risk management activities for both
trading and non-trading purposes. The Corporation conducts trading
activities through its gas and power marketing subsidiaries using a variety
of financial instruments. These instruments include forward contracts
involving the physical delivery of an energy commodity, swap agreements,
futures, options, and other contractual arrangements. Additionally, the
Corporation engages in non-trading activities using futures, options, and
<PAGE>
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies.
Any gain or loss on derivatives used in hedging activities is deferred
until the gain or loss on the hedged item is recognized. To qualify for
hedge treatment, the underlying hedged item must expose the Corporation to
risks associated with market fluctuations and the financial instrument used
must be designated as a hedge and must reduce the Corporation's exposure to
market fluctuations throughout the hedge period. If these criteria are not
met, a change in the market value of the financial instrument is recognized
as a gain or loss in the period of change. The cash flow resulting from a
hedge is classified with the corresponding cash flow of the item being
hedged. When there is an early termination of a financial instrument
designated as a hedge, the gain or loss will continue to be deferred until
the offsetting loss or gain is recognized on the underlying hedged item.
Gains and losses associated with trading activities during year-to-date
1997 were immaterial.
Acquisitions and Sales:
- ----------------------
In December 1996, PGT acquired Energy Source (which was renamed PG&E Energy
Trading Corporation) for approximately $23 million. On June 30, 1997, PGT
distributed all of the shares of PG&E Energy Trading Corporation to PG&E
Corporation.
PG&E Energy Trading Corporation, PG&E Corporation's wholesale commodity
marketing subsidiary, has averaged $277 million in revenues each month since
January 1997. These revenues were primarily offset by a corresponding
increase in the cost of gas.
In January 1997, the Corporation acquired Teco Pipeline Company (renamed
PG&E Gas Transmission Teco, Inc.) for approximately $380 million, consisting
of $319 million of PG&E Corporation common stock and the purchase of a $61
million note.
On April 2, 1997, Bechtel Enterprises, Inc. (Bechtel) acquired
Enterprises' interest in International Generating Company, Ltd., a joint
venture between Enterprises and Bechtel. The sale resulted in an after-tax
gain of approximately $110 million, which was recorded in April 1997.
On June 26, 1997, the Corporation announced its agreement to acquire
Bechtel's interests in U.S. Generating Company (USGen), operations and
maintenance affiliate U.S. Operating Services Company, and power marketing
affiliate USGen Power Services, L.P., by redemption of Bechtel's interests
in such partnerships. In addition, the Corporation has agreed to purchase
Bechtel's interest in certain independent power projects currently owned by
Bechtel and PG&E Corporation (through Enterprises) or by Bechtel, PG&E
Corporation, and various third parties. USGen is a joint venture formed by
PG&E and Bechtel in 1989 to develop, own, and manage independent power
production facilities in North America. The purchase is expected to be
completed by December 31, 1997.
On July 31, 1997, the Corporation completed its acquisition of Valero
Energy Corporation (Valero) (which was renamed PG&E Gas Transmission, Texas
Corporation), including its natural gas and natural gas liquids business,
but excluding its refining operations. The outstanding shares of Valero
common stock were converted into PG&E Corporation common stock for a total
issuance of approximately 31,000,000 shares. The purchase price of Valero
was approximately $771 million, and approximately $800 million in long-term
debt was assumed. The acquisition was accounted for as a purchase.
On August 6, 1997, the Corporation announced that USGen (through a
special purpose entity wholly owned by PG&E Corporation) had agreed to
<PAGE>
acquire a portfolio of non-nuclear electric generating assets and power
supply contracts from the New England Electric System for approximately
$1.59 billion, plus $85 million to cover early retirement and severance
costs. Including fuel, other inventories, and transaction costs, financing
requirements are expected to total approximately $1.75 billion. The
assets to be acquired contain a mix of hydro, coal, oil, and gas generation
and represent the second largest non-nuclear electric generation portfolio
in New England, comprising approximately 17 percent of New England's total
installed generating capacity. The acquisition of these assets, which is
subject to approval of the Federal Energy Regulatory Commission and state
regulators, among other conditions, is expected to be completed in 1998.
NOTE 2: ELECTRIC INDUSTRY RESTRUCTURING
In 1995, the California Public Utilities Commission (CPUC) issued a decision
that provides a plan to restructure California's electric utility industry.
The decision acknowledges that much of utilities' current costs and
commitments result from past CPUC decisions and that, in a competitive
generation market, utilities would not recover some of these costs through
market-based revenues. To assure the continued financial integrity of
California utilities, the CPUC authorized recovery of these above-market
costs, called "transition costs."
In 1996, California legislation (restructuring legislation) was passed
that adopts the basic tenets of the CPUC's restructuring decision,
including recovery of transition costs. In addition, the restructuring
legislation provides a 10 percent electric rate reduction for residential
and small commercial customers by January 1, 1998, freezes electric
customer rates for all customers, and requires the accelerated recovery of
transition costs associated with owned electric generation facilities. The
restructuring legislation also establishes the operating framework for a
competitive electric generation market. The rate freeze, mandated by the
restructuring legislation, will continue until the earlier of March 31,
2002, or until PG&E has recovered its authorized transition costs (the
transition period).
To achieve the 10 percent rate reduction, the restructuring legislation
authorizes utilities to finance a portion of their transition costs with
"rate reduction bonds." The maturity period of the bonds is expected to
extend beyond the transition period. Also, the interest cost of the bonds
is expected to be lower than PG&E's current weighted-average cost of
capital. Once the bonds are issued, PG&E would collect a separate tariff on
behalf of the bondholders to recover principal, interest, and issuance costs
over the life of the bonds from residential and small commercial customers.
The combination of the longer maturity period and the reduced interest costs
is expected to lower the amounts paid by these customers each year during
the transition period, thereby achieving the 10 percent reduction in rates.
In May 1997, PG&E filed an application with the CPUC for the issuance of
an estimated $3.1 billion of these bonds by means of a special purpose
entity. A CPUC decision is expected in September 1997. If the decision is
approved, PG&E expects these bonds would be issued in the fourth quarter of
1997.
During 1997, differences between authorized and actual base revenues
(revenues to recover PG&E's non-energy costs and return on investment) and
differences between the actual electric energy costs and the revenue
designated for recovery of such costs are being recorded in balancing
accounts. Any residual balance will be available to use for recovery of
transition costs. PG&E expects this residual balance to be approximately
$340 million at December 31, 1997. Amounts recorded in balancing accounts
will be subject to a reasonableness review by the CPUC.
<PAGE>
Transition Cost Recovery:
- ------------------------
The restructuring legislation authorizes the CPUC to determine the costs
eligible for recovery as transition costs. The amount of costs will be
based on, among other things, the aggregate of above-market and below-
market values of utility-owned generation assets and obligations. Costs
eligible for transition cost recovery include: (1) above-market sunk costs
(costs associated with utility generating facilities that are fixed and
unavoidable and currently collected through rates) and future 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 period and allowed to be included in rates
in subsequent periods.) PG&E cannot determine the exact amount of sunk
costs that will be above market and recoverable as transition costs until a
market valuation process (appraisal or sale) is completed for each
generation facility. This process will be completed during the transition
period.
In compliance with the CPUC's restructuring decision and the
restructuring legislation, PG&E has filed numerous regulatory applications
and proposals that detail its transition cost recovery plan. PG&E's
recovery plan includes: (1) separation or unbundling of its previously
approved cost-of-service revenues for its electric operations into
distribution, transmission, public purpose programs, and generation, (2)
development of a ratemaking mechanism to track and match revenues and cost
recovery during the transition period, and (3) accelerated recovery of
transition costs.
In applying its recovery plan to Diablo Canyon Nuclear Power Plant (Diablo
Canyon), PG&E proposed: (1) recovery of certain ongoing costs and capital
additions through a rate based upon Diablo Canyon generation, and (2) fixed
recovery of PG&E's investment in Diablo Canyon by the end of 2001. In May
1997, the CPUC issued a decision on PG&E's proposal. The decision was
effective January 1, 1997, and generally adopts the overall ratemaking
structure proposed by PG&E. This ratemaking structure has caused a
significant change in the way Diablo Canyon earns revenues from the previous
performance-based ratemaking (PBR) mechanism as follows:
1. Diablo Canyon's sunk costs will be fully recovered during the
transition period, at a reduced return on common equity equal to 90 percent
of PG&E's embedded cost of debt. PG&E's authorized long-term cost of debt
was 7.52 percent in 1996. Recovery of Diablo Canyon will be accelerated
from a twenty-year period ending in 2016 to a five-year period ending in
2001.
2. Revenues for recovery of on-going operating costs and capital additions
will be computed through a PBR mechanism. This mechanism establishes a rate
per kilowatt-hour (kWh), generated by the facility, called the Incremental
Cost Incentive Price (ICIP).
Although the CPUC adopted PG&E's overall structure, as described below,
the CPUC decision (1) substantially reduces the ICIP from the level proposed
by PG&E, (2) excludes certain items from the sunk cost revenue requirement,
and (3) imposes a disallowance of about $70 million. In addition, the
decision fails to clarify Diablo Canyon's "must take" status during the
transition period although language supporting must take status is contained
within the CPUC's 1995 restructuring decision. Without must take status,
Diablo Canyon generation during the transition period may be significantly
reduced, which would reduce recovery of ICIP related costs. The following
table summarizes the authorized revenues and ICIP per this decision:
<PAGE>
1997 1998 1999 2000 2001
- ----------------------------------------------------------------------------
ICIP (cents per kWh) 3.26 3.31 3.37 3.43 3.49
Estimated Total Authorized Revenues
($ in millions)
Sunk Cost Recovery $1,385 $1,322 $1,259 $1,197 $1,135
ICIP Revenues 515 523 532 542 552
- ----------------------------------------------------------------------------
Total Authorized Revenues $1,900 $1,845 $1,791 $1,739 $1,687
The CPUC decision adopts a fixed forecast of ICIP rates for 1997 through
2001, which is substantially lower than those proposed by PG&E. The
difference in prices results principally from different assumptions used in
forecasts of Diablo Canyon capacity factors, operating and maintenance
costs, and escalation factors. The prices in the CPUC decision are based on
an assumed capacity factor of 83.6 percent and an escalation factor of 1.5
percent.
Further, the CPUC decision finds that PG&E's proposed modified Diablo
Canyon ratemaking is a form of traditional ratemaking subject to a state
statute requiring a prudence review of the plant's construction costs and
requiring a disallowance of any such costs exceeding $50 million which
result from an unreasonable construction error or omission. The decision
then finds that PG&E admitted to an error in the design and construction of
the plant of $100 million and accordingly adopts a prudence disallowance of
approximately $70 million for the undepreciated portion of costs
attributable to the error.
This disallowance reduces the amount of revenues collected over the five
year recovery period. However, this reduction in revenue does not result in
an impairment. PG&E has requested that the CPUC rehear its decision and
eliminate the sunk cost disallowances from the decision. A consumer group
also has filed a rehearing request, asking the CPUC to order a full prudence
hearing on all the Diablo Canyon sunk costs before permitting any of the
costs to be recovered. PG&E expects the CPUC to act on the rehearing
requests by the end of the year.
Based upon the Diablo Canyon decision, the restructuring legislation,
the CPUC's restructuring decision, and existing PG&E applications and
proposals which would take effect in 1997, PG&E is depreciating Diablo
Canyon over a five-year period ending in 2001. This five-year depreciation
is consistent with PG&E's cost recovery plan which provides sunk cost
revenues over the same period. The change in depreciable life increased
Diablo Canyon's depreciation expense for the first six months of the year
by $289 million, for an after-tax reduction to earnings per share of $.43.
Under the restructuring legislation, most transition costs must be
recovered by March 31, 2002. However, the restructuring legislation
authorizes recovery of certain transition costs after that time. These
costs include: (1) certain employee-related transition costs, (2) payments
under existing QF and power purchase contracts, and (3) unrecovered
implementation costs. In addition, transition costs financed by the
issuance of rate reduction bonds are expected to be recovered over the term
of the bonds. Excluding these exceptions, any transition costs not
recovered during the transition period would be absorbed by PG&E. Nuclear
decommissioning costs, which are not considered transition costs, will be
recovered through a CPUC authorized charge. During the transition period,
this charge will be incorporated into the frozen electric rates.
<PAGE>
PG&E's ability to recover its transition costs during the transition
period will be dependent on several factors. These factors include: (1) the
extent to which the regulatory framework established by the restructuring
legislation will continue to be applied, (2) the amount of transition costs
approved by the CPUC, (3) the market value of PG&E's generation plants, (4)
future sales levels, (5) future fuel and operating costs, and (6) the market
price of electricity. Given its current evaluation of these factors, PG&E
believes it will recover its transition costs and that its utility-owned
generation plants are not impaired. However, a change in one or more these
factors could affect the probability of recovery of transition costs and
result in a material loss.
Accounting for the Effects of Regulation:
- ----------------------------------------
PG&E accounts for the financial effect of regulation in accordance with
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation." This statement allows PG&E to
record certain regulatory assets and liabilities which would be included in
future rates and would not be recorded under generally accepted accounting
principles for nonregulated entities. In addition, SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," requires that regulatory assets be written off
when they are no longer probable of recovery and that impairment losses be
recorded for long-lived assets when related future cash flows are less than
the carrying value of the assets.
In applying the provisions of SFAS No. 71, PG&E has accumulated
approximately $1.7 billion of regulatory assets attributable to electric
generation at June 30, 1997. The net investments in Diablo Canyon and the
other generation assets, including allocation of common plant, were $4.1
billion and $2.7 billion, respectively, at June 30, 1997. The net present
value of above-market QF power purchase obligations is estimated to be $5.3
billion at January 1, 1998, at an assumed market price of $0.025 per kWh
beginning in 1997 and escalating at 3.2 percent per year.
PG&E believes that the restructuring legislation establishes a definitive
transition to the market-based pricing for electric generation that includes
recovery of the transition costs through a nonbypassable charge (the
competition transition charge or CTC). At the conclusion of the transition
period, PG&E believes it will be at risk to recover its generation costs
through market-based revenues.
As a result of California's electric industry restructuring and related
legislation, in 1996 the staff of the SEC began discussions with PG&E and
other California utilities regarding the appropriateness of the continued
application of SFAS No. 71 for the generation portion of the electric
utilities' businesses as of January 1, 1997. Because of the importance of
this issue to the electric utility industry in the United States, the SEC
referred the issue to the Emerging Issues Task Force (EITF) of the
Financial Accounting Standards Board (FASB).
In its meeting on July 24, 1997, the EITF reached a consensus on EITF
Issue No. 97-4 "Deregulation of the Pricing of Electricity - Issues Related
to the Application of FASB Statements No. 71, Accounting for the Effects of
Certain Types of Regulation, and No. 101, Regulated Enterprises -
Accounting for the Discontinuation of Application of FASB Statement No. 71"
(EITF 97-4). The consensus will require PG&E to discontinue the
application of SFAS No. 71 for the generation portion of its operations as
of July 24, 1997, the effective date of EITF 97-4. The discontinuation of
application of SFAS No. 71 will not have a material effect on PG&E's
financial statements because EITF 97-4 requires that regulatory assets and
liabilities (both those in existence today and those created under the
terms of the transition plan) be allocated to the portion of the business
from which the source of the regulated cash flows are derived. Under the
<PAGE>
terms of PG&E's transition cost recovery plan, approved by the CPUC in
1996, PG&E's generation related regulatory assets and liabilities,
including uncollected CTC, will be recovered through a CTC imposed on the
distribution customers during the transition period. EITF 97-4 will become
final upon approval of the minutes of the July 24 meeting, which is
expected in August 1997.
Given the current regulatory environment, PG&E's electric transmission
business and most areas of the distribution business are expected to remain
regulated and, as a result, PG&E will continue to apply the provisions of
SFAS No. 71. However, in May 1997, the CPUC issued decisions that allow
customers to choose their electricity provider beginning January 1, 1998.
The decisions also allow the electricity provider to provide their customers
with billing and metering services, and indicate that electricity providers
may be allowed to provide other distribution services (such as customer
inquiries and uncollectibles) in the future. Any discontinuation of SFAS
No. 71 for these portions of PG&E's electric distribution business is not
expected to have a material adverse impact on the Corporation's or PG&E's
financial position or results of operations.
NOTE 3: NATURAL GAS MATTERS
On August 1, 1997, the CPUC unanimously adopted a final decision approving
the Gas Accord Settlement (Accord), which was submitted in 1996 for CPUC
approval. The Accord will restructure PG&E's gas services and its role in
the gas market, establish gas transmission rates for the five-year period
from implementation of the Accord (expected to be December 1, 1997) through
December 2002, establish an incentive mechanism to measure the
reasonableness of PG&E's purchases of gas for core customers, and resolve
various gas regulatory issues.
In addition, the final decision accepts the Accord's proposal to set
rates for Line 401 (the California segment of the PG&E/PGT pipeline) based
on total capital costs of $736 million. It also adopts a discounting rule,
whereby whenever PG&E offers a rate discount Line 401, it must also offer
the same discount on pipelines transporting Southwestern and in-state gas
production. The final decision approves the Accord's proposal that PG&E
forgo recovery of 100 percent and 50 percent of the Interstate Transition
Cost Surcharge amounts allocated for collection from its residential and
smaller commercial customers and industrial and larger commercial customers,
respectively. Finally, the decision states that the CPUC's intention to
implement the rates and other provisions of the Accord throughout the Accord
period is subject to the CPUC's overreaching policy goals and the CPUC's
decisions reached in the CPUC's natural gas industry strategic plan to
produce a more competitive gas market.
As of June 30, 1997, approximately $490 million had been reserved
relating to these gas regulatory issues and capacity commitments. As a
result, the Corporation believes that the decision will not have a material
adverse impact on its or PG&E's financial position or results of operations.
NOTE 4: PG&E OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST
HOLDING SOLELY PG&E SUBORDINATED DEBENTURES
PG&E, through its wholly owned subsidiary, PG&E Capital I (Trust), has
outstanding 12 million shares of 7.90% cumulative quarterly income preferred
securities (QUIPS), with an aggregate liquidation value of $300 million.
Concurrent with the issuance of the QUIPS, the Trust issued to PG&E 371,135
<PAGE>
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 PG&E with a face value of
approximately $309 million, an interest rate of 7.90%, and a maturity date
of 2025.
NOTE 5: COMMITMENTS AND CONTINGENCIES
Nuclear Insurance:
- -----------------
PG&E has insurance coverage for property damage and business interruption
losses as a member of Nuclear Mutual Limited (NML) and Nuclear Electric
Insurance Limited (NEIL). Under these policies, if a nuclear generating
facility suffers a loss due to a prolonged accidental outage, PG&E may be
subject to maximum assessments of $28 million (property damage) and $7
million (business interruption), in each case per policy period, in the
event losses exceed the resources of NML or NEIL.
PG&E has purchased primary insurance of $200 million for public liability
claims resulting from a nuclear incident. An additional $8.7 billion of
coverage is provided by secondary financial protection which is mandated by
federal legislation and 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, PG&E may be assessed
up to $159 million per incident, with payments in each year limited to a
maximum of $20 million per incident.
Environmental Remediation:
- -------------------------
PG&E may be required to pay for environmental remediation at sites where
PG&E has been or may be a potentially responsible party under the
Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) or the California Hazardous Substance Account Act. These sites
include former manufactured gas plant sites, power plant sites, and sites
used by PG&E for the storage or disposal of materials which may be
determined to present a significant threat to human health or the
environment because of an actual or potential release of hazardous
substances. Under CERCLA, PG&E's financial responsibilities may include
remediation of hazardous substances, even if PG&E did not deposit those
substances on the site.
PG&E records a liability when site assessments indicate remediation is
probable and a range of reasonably likely cleanup costs can be estimated.
PG&E reviews its sites and measures the liability quarterly, by assessing a
range of reasonably likely costs for each identified site using currently
available information, including existing technology, presently enacted
laws and regulations, experience gained at similar sites, and the probable
level of involvement and financial condition of other potentially
responsible parties. These estimates include costs for site
investigations, remediation, operations and maintenance, monitoring, and
site closure. Unless there is a better estimate within this range of
possible costs, PG&E records the lower end of this range.
The cost of the hazardous substance remediation ultimately undertaken by
PG&E is difficult to estimate. It is reasonably possible that a change in
the estimate will occur in the near term due to uncertainty concerning
PG&E's responsibility, the complexity of environmental laws and
regulations, and the selection of compliance alternatives. PG&E had an
accrued liability at June 30, 1997, of $221 million for hazardous waste
remediation costs at those sites, including fossil-fuel power plants, where
<PAGE>
such costs are probable and quantifiable. Environmental remediation at
identified sites may be as much as $489 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 at sites for which PG&E is responsible. This upper limit of
the range of costs was estimated using assumptions least favorable to PG&E,
based upon a range of reasonably possible outcomes. Costs may be higher if
PG&E is found to be responsible for cleanup costs at additional sites or
identifiable possible outcomes change.
PG&E will seek recovery of prudently incurred hazardous substance
remediation costs through ratemaking procedures approved by the CPUC. PG&E
has recorded regulatory assets at June 30, 1997, of $152 million for
recovery of these costs in future rates. Additionally, PG&E will seek
recovery of costs from insurance carriers and from other third parties as
appropriate. The Corporation believes the ultimate outcome of these matters
will not have a material adverse impact on its or PG&E's financial position
or results of operations.
Helms Pumped Storage Plant (Helms):
- ----------------------------------
Helms is a three-unit hydroelectric combined generating and pumped storage
plant. At June 30, 1997, PG&E's net investment was $700 million. This net
investment is comprised of the pumped storage facility (including
regulatory assets of $50 million), common plant, and dedicated transmission
plant. As part of the 1996 General Rate Case decision in December 1995,
the CPUC directed PG&E to perform a cost-effectiveness study of Helms. In
July 1996, PG&E submitted its study, which concluded that the continued
operation of Helms is cost effective. PG&E recommended that the CPUC take
no action and address Helms along with other generating plants in the
context of electric industry restructuring.
PG&E is currently unable to predict whether there will be a change in
rate recovery resulting from the study. As with its other hydroelectric
generating plants, PG&E expects to seek recovery of its net investment in
Helms through either PBR or cost of service ratemaking and through
transition cost recovery. The Corporation believes that the ultimate
outcome of this matter will not have a material adverse impact on its or
PG&E's financial position or results of operations.
Legal Matters:
- -------------
Cities Franchise Fees Litigation:
In 1994, the City of Santa Cruz filed a class action suit in a California
state superior court (Court) against PG&E on behalf of itself and 106 other
cities in PG&E's service area. The complaint alleges that PG&E has
underpaid electric franchise fees to the cities by calculating those fees at
different rates from other cities not included in the complaint.
In September 1995, the Court certified the class of 107 cities in this
suit and approved the City of Santa Cruz as the class representative. In
January and March 1996, the Court made two rulings against certain cities
effectively eliminating a major portion of the suit. The Court's rulings
do not resolve the suit completely. The cities appealed both rulings. The
trial has been postponed pending the cities' appeal.
Should the cities prevail on the issue of franchise fee calculation
methodology, PG&E's annual systemwide city electric franchise fees could
increase by approximately $16 million and damages for alleged underpayments
<PAGE>
for the years 1987 to 1996 could be as much as $147 million (exclusive of
interest, estimated to be $44 million at June 30, 1997). If the Court's
January and March 1996 rulings become final, PG&E's annual systemwide city
electric franchise fees for the remaining class member cities not subject to
the Court's rulings could increase by approximately $5 million and damages
for alleged underpayments for the years 1987 to 1996 could be as much as $40
million (exclusive of interest, estimated to be $12 million at June 30,
1997).
The Corporation believes that the ultimate outcome of this matter will
not have a material adverse impact on its or PG&E's financial position or
results of operations.
Chromium Litigation:
In 1994 through 1997, several civil complaints were filed against PG&E on
behalf of approximately 3,000 individuals. The complaints seek an
unspecified amount of compensatory and punitive damages for alleged personal
injuries resulting from alleged exposure to chromium in the vicinity of
PG&E's gas compressor stations at Hinkley, Kettleman, and Topock.
PG&E is responding to the complaints and asserting affirmative defenses.
PG&E 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.
The Corporation believes that the ultimate outcome of this matter will
not have a material adverse impact on its or PG&E's financial position or
results of operations.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The "Management's Discussion And Analysis Of Financial Condition And Results
Of Operations" herein pertain to Pacific Gas and Electric Company (PG&E) and
its new parent holding company, PG&E Corporation, of which PG&E became a
subsidiary effective January 1, 1997.
PG&E Corporation's consolidated financial statements include the accounts
of the following, as well as the accounts of their wholly owned and
controlled subsidiaries (collectively, the Corporation):
- - PG&E Corporation
- - PG&E
- - PG&E Gas Transmission Corporation consisting of Pacific Gas Transmission
Company (PGT) including its operations in Australia, and the pipeline and
on-system marketing segments of PG&E Gas Transmission Teco, Inc. (formerly
PG&E Gas Transmission, Texas Corporation)
- - PG&E Energy Trading Corporation (formerly Energy Source), and the off-
system marketing segment of PG&E Gas Transmission Teco, Inc. (formerly
PG&E Gas Transmission, Texas Corporation)
- - PG&E Energy Services Corporation (formerly Vantus Energy Corporation)
- - PG&E Enterprises (Enterprises)
It should be noted that the discussion and analysis of PG&E's financial
condition and results of operations also apply to the Corporation since
PG&E's financial condition and results of operations are currently 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 PG&E's Consolidated Financial
<PAGE>
Statements and Notes to Consolidated Financial Statements incorporated by
reference in their combined 1996 Annual Report on Form 10-K.
The following discussion of consolidated results of operations and
financial condition contains forward-looking statements that involve risks
and uncertainties. These forward-looking statements include discussion of
the financial impacts of gas and electric industry restructuring. Words such
as "estimates," "expects," "anticipates," "plans," "believes," and similar
expressions also identify forward-looking statements involving risks and
uncertainties.
These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric and gas industries, the outcome of the
regulatory proceedings related to that restructuring, PG&E's ability to
collect revenues sufficient to recover transition costs in accordance with
its cost recovery plan, the impact of the Corporation's recently announced
or completed acquisitions, and the ability of the Corporation to
successfully compete outside its traditional regulated markets. The
ultimate impacts on future results of increased competition, the changing
regulatory environment, and the Corporation's expansion into new businesses
and markets are uncertain, but all are expected to fundamentally change how
the Corporation conducts its business. The outcome of these changes and
other matters discussed below may cause future results to differ materially
from historic results, or from results or outcomes currently expected or
sought by the Corporation and PG&E.
COMPETITION AND CHANGING REGULATORY ENVIRONMENT:
The electric and gas industries are undergoing significant change. Under
traditional regulation, utilities were provided the opportunity to earn a
fair return on their invested capital in exchange for a commitment to serve
all customers within a designated service territory. The objective of this
regulatory policy was to provide universal access to safe and reliable
utility services. Regulation was designed in part to take the place of
competition and to ensure that these services were provided at fair prices.
Today, competitive pressures and emerging market forces are exerting an
increasing influence over the structure of the gas and electric industries.
Customers are asking for choice in their energy provider. Other companies
are challenging the utilities' exclusive relationship with customers and are
seeking to replace certain utility functions with their own. These pressures
are causing a move from the existing regulatory framework to a framework
under which competition would be allowed in certain segments of the gas and
electric industries.
For several years, PG&E has been working with its regulators to achieve
an orderly transition to competition and to ensure that PG&E has an
opportunity to recover investments made under the traditional regulatory
policies. In addition, PG&E has proposed alternative forms of regulation
for those services for which prices and terms will not be determined by
competition. These alternative forms include performance-based ratemaking
(PBR) and other incentive-based alternatives. Over the next five years, a
significant portion of PG&E's business will be transformed from the current
utility monopoly to a competitive operation. This change will impact PG&E's
financial results and may result in greater earnings volatility. In
addition, during the transition period, PG&E expects the return on Diablo
Canyon Nuclear Power Plant (Diablo Canyon) and certain other generation
assets to be significantly lower than historical levels.
<PAGE>
ELECTRIC INDUSTRY RESTRUCTURING:
In 1995, the California Public Utilities Commission (CPUC) issued a decision
that provides a plan to restructure California's electric utility industry.
The decision acknowledges that much of utilities' current costs and
commitments result from past CPUC decisions and that, in a competitive
generation market, utilities would not recover some of these costs through
market-based revenues. To assure the continued financial integrity of
California utilities, the CPUC authorized recovery of these above-market
costs, called "transition costs."
In 1996, California legislation (restructuring legislation) was passed
that adopts the basic tenets of the CPUC's restructuring decision, including
recovery of transition costs. In addition, the restructuring legislation
provides a 10 percent electric rate reduction for residential and small
commercial customers by January 1, 1998, freezes electric customer rates for
all customers, and requires the accelerated recovery of transition costs
associated with owned electric generation facilities. The restructuring
legislation also establishes the operating framework for a competitive
electric generation market. The rate freeze, mandated by the restructuring
legislation, would continue until the earlier of March 31, 2002, or until
PG&E has recovered its authorized transition costs (the transition period).
To achieve the 10 percent rate reduction, the restructuring legislation
authorizes utilities to finance a portion of their transition costs with
"rate reduction bonds." The maturity period of the bonds is expected to
extend beyond the transition period. Also, the interest cost of the bonds
is expected to be lower than PG&E's current weighted-average cost of
capital. Once the bonds are issued, PG&E would collect a separate tariff
on behalf of the bondholders to recover principal, interest, and issuance
costs over the life of the bonds from residential and small commercial
customers. The combination of the longer maturity period and the reduced
interest costs is expected to lower the amounts paid by these customers
each year during the transition period, thereby achieving the 10 percent
reduction in rates.
During 1997, differences between authorized and actual base revenues
(revenues to recover PG&E's non-energy costs and return on investment) and
differences between the actual electric energy costs and the revenue
designated for recovery of such costs are being recorded in balancing
accounts. Any residual balance will be available to use for recovery of
transition costs. PG&E expects this residual balance to be approximately
$340 million at December 31, 1997. Amounts recorded in balancing accounts
will be subject to a reasonableness review by the CPUC.
The most significant factors contributing to the expected residual
balance are the declining cost of power committed under certain purchased
power contracts, the reduction in the Diablo Canyon price for power under
the CPUC-approved settlement (see below), and the decline in uncollected
electric balancing accounts.
Transition Cost Recovery:
- ------------------------
The restructuring legislation authorizes the CPUC to determine the costs
eligible for recovery as transition costs. The amount of costs will be
based on, among other things, the aggregate of above-market and below-market
values of utility-owned generation assets and obligations. Costs eligible
for transition cost recovery include: (1) above-market sunk costs (costs
associated with utility generating facilities that are fixed and unavoidable
and currently collected through rates) and future 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
<PAGE>
obligations. (In general, regulatory assets are expenses deferred in the
current period and allowed to be included in rates in subsequent periods.)
PG&E cannot determine the exact amount of sunk costs that will be above
market and recoverable as transition costs until a market valuation process
(appraisal or sale) is completed for each generation facility. This process
will be completed during the transition period.
In compliance with the CPUC's restructuring decision and the
restructuring legislation, PG&E has filed numerous regulatory applications
and proposals that detail its transition cost recovery plan. PG&E's
recovery plan includes: (1) separation or unbundling of its previously
approved cost-of-service revenues for its electric operations into
distribution, transmission, public purpose programs (PPPs), and generation,
(2) development of a ratemaking mechanism to track and match revenues and
cost recovery during the transition period, and (3) accelerated recovery of
transition costs.
The unbundling of PG&E's revenue requirement would enable it to separate
revenue provided by frozen rates into transmission, distribution, PPPs, and
generation. As proposed, revenues collected under frozen rates would be
assigned to transmission, distribution, and PPPs based upon their respective
cost of service. Revenue would also be provided for other costs, including
nuclear decommissioning, rate-reduction-bond debt service, the on-going cost
of generation, and transition cost recovery.
In August 1997, the CPUC issued a decision on PG&E's proposed unbundling
of its 1998 authorized electric revenues. The decision adopts PG&E's
overall revenue allocation methodology with the following exceptions. The
decision reallocates approximately $49 million of distribution revenue to
the generation and transmission functions subject to adjustment after any
divestiture of power plants, discussed below. In addition, the decision
requires that the competition transition charge (CTC) imposed on the
customers should be determined residually based upon a monthly class average
power exchange (PX) price, rather than on an hour by hour price as
originally proposed. Further, the decision rejects PG&E's proposal that the
distribution authorized revenues should be determined by subtracting
transmission revenues, approved by the Federal Energy Regulatory Commission
(FERC), from the sum of the CPUC-approved transmission and distribution
revenues. Instead, the distribution revenues, authorized by the CPUC, and
the transmission revenues, authorized by the FERC, would be determined on a
stand-alone basis. PG&E does not believe the decision will have a material
impact on its ability to recover transition costs.
Under PG&E's recovery plan, PG&E would receive a reduced return on common
equity for certain transition costs related to generation facilities for
which recovery is accelerated during the transition period. The lower
return reflects the reduced risk associated with the shorter amortization
period and increased certainty of recovery. The Office of Ratepayers
Advocates (ORA) of the CPUC has filed a motion requesting that the reduced
rate of return be applied to all generation-related assets in 1997, prior to
the transition period. The ORA believes that this reduced rate of return
reflects PG&E's reduced risk resulting from the CPUC's authorization of
PG&E's cost recovery plan. In July 1997, the CPUC ordered the utilities to
establish memorandum accounts to track the differences between the
authorized rate of return and the reduced rate of return, pending a final
CPUC decision on the issue.
In applying its recovery plan to Diablo Canyon, PG&E proposed: (1)
recovery of certain ongoing costs and capital additions through a rate
based upon Diablo Canyon generation, and (2) fixed recovery of PG&E's
investment in Diablo Canyon by the end of 2001. In May 1997, the CPUC
issued a decision on PG&E's proposal. The decision was effective January
1, 1997, and generally adopts the overall ratemaking structure proposed by
PG&E. This ratemaking structure has caused a significant change in the way
Diablo Canyon earns revenues from the previous PBR mechanism as follows:
<PAGE>
1. Diablo Canyon's sunk costs will be fully recovered during the
transition period at a reduced return on common equity equal to 90 percent
of PG&E's embedded cost of debt. PG&E's authorized long-term cost of debt
was 7.52 percent in 1996. Recovery of Diablo Canyon will be accelerated
from a twenty-year period ending in 2016 to a five-year period ending in
2001.
2. Revenues for recovery of on-going operating costs and capital additions
will be computed through a PBR mechanism. This mechanism establishes a rate
per kilowatt-hour (kWh), generated by the facility, called the Incremental
Cost Incentive Price (ICIP).
Although the CPUC adopted PG&E's overall structure, as described below,
the CPUC decision (1) substantially reduces the ICIP from the level
proposed by PG&E, (2) excludes certain items from the sunk cost revenue
requirement, and (3) imposes a disallowance of about $70 million. In
addition, the decision fails to clarify Diablo Canyon's "must take" status
during the transition period although language supporting must take status
is contained within the CPUC's 1995 restructuring decision. Without must
take status, Diablo Canyon generation during the transition period may be
significantly reduced, which would reduce recovery of ICIP related costs.
The following table summarizes the authorized revenues and ICIP prices per
this decision:
1997 1998 1999 2000 2001
- ----------------------------------------------------------------------------
ICIP (cents per kWh) 3.26 3.31 3.37 3.43 3.49
Estimated Total Authorized Revenues
($ in millions)
Sunk Cost Recovery $1,385 $1,322 $1,259 $1,197 $1,135
ICIP Revenues 515 523 532 542 552
- ----------------------------------------------------------------------------
Total Authorized Revenues $1,900 $1,845 $1,791 $1,739 $1,687
The CPUC decision adopts a fixed forecast of ICIP rates for 1997 through
2001, which is substantially lower than those proposed by PG&E. The
difference in prices results principally from different assumptions used in
forecasts of Diablo Canyon capacity factors, operating and maintenance
costs, and escalation factors. The prices in the CPUC decision are based
on an assumed capacity factor of 83.6 percent and an escalation factor of
1.5 percent.
Further, the CPUC decision finds that PG&E's proposed modified Diablo
Canyon ratemaking is a form of traditional ratemaking subject to a state
statute requiring a prudence review of the plant's construction costs and
requiring a disallowance of any such costs exceeding $50 million which
result from an unreasonable construction error or omission. The decision
then finds that PG&E admitted to an error in the design and construction of
the plant of $100 million and accordingly adopts a prudence disallowance of
approximately $70 million for the undepreciated portion of costs
attributable to the error.
This disallowance reduces the amount of revenues collected over the five
year recovery period. However, this reduction in revenue does not result
in an impairment. PG&E has requested that the CPUC rehear its decision and
eliminate the sunk cost disallowances from the decision. A consumer group
also has filed a rehearing request, asking the CPUC to order a full
prudence hearing on all the Diablo Canyon sunk costs before permitting any
<PAGE>
of the costs to be recovered. PG&E expects the CPUC to act on the
rehearing requests by the end of the year.
Based upon the Diablo Canyon decision, the restructuring legislation,
the CPUC's restructuring decision, and existing PG&E applications and
proposals which would take effect in 1997, PG&E is depreciating Diablo
Canyon over a five-year period ending in 2001. This five-year depreciation
is consistent with PG&E's cost recovery plan which would provide sunk cost
revenues over the same period. The change in depreciable life increased
Diablo Canyon's depreciation expense for the first six months of the year
by $289 million, for an after-tax reduction to earnings per share of $.43.
Under the restructuring legislation, most transition costs must be
recovered by March 31, 2002. However, the restructuring legislation
authorizes recovery of certain transition costs after that time. These
costs include: (1) certain employee-related transition costs, (2) payments
under existing QF and power purchase contracts, and (3) unrecovered
implementation costs. In addition, transition costs financed by the
issuance of rate reduction bonds are expected to be recovered over the term
of the bonds. Excluding these exceptions, any transition costs not
recovered during the transition period would be absorbed by PG&E. Nuclear
decommissioning costs, which are not considered transition costs, will be
recovered through a CPUC authorized charge. During the transition period,
this charge will be incorporated into the frozen electric rates.
PG&E's ability to recover its transition costs during the transition
period will be dependent on several factors. These factors include: (1)
the extent to which the regulatory framework established by the
restructuring legislation will continue to be applied, (2) the amount of
transition costs approved by the CPUC, (3) the market value of PG&E's
generation plants, (4) future sales levels, (5) future fuel and operating
costs, and (6) the market price of electricity. Given its current
evaluation of these factors, PG&E believes it will recover its transition
costs and that its utility-owned generation plants are not impaired.
However, a change in one or more of these factors could affect the
probability of recovery of transition costs and result in a material loss.
Competitive Market Framework:
- ----------------------------
In addition to transition cost recovery, the restructuring legislation
establishes the operating framework for the competitive generation market
in California. This framework will consist of a PX and an independent
system operator (ISO). The PX, open to all electricity providers, will
conduct a competitive auction to establish the price of electricity. The
ISO is expected to ensure transmission system reliability and provide all
electricity generators with open and comparable access to transmission
services.
Although the PX will be available to all customers through their local
utility, the restructuring legislation allows customers to purchase
electricity directly from electricity providers. These customers are
referred to as direct access customers. In May 1997, the CPUC issued two
decisions related to direct access: the direct access decision and the
revenue cycle services decision.
Under the direct access decision, beginning January 1, 1998, all
electric customers may choose their electricity provider. Customers may
choose to purchase their electricity (1) from the PX through PG&E, (2) from
retail electricity providers (for example, marketers, brokers, and
aggregators), or (3) directly from power generators. Regardless of the
customer's choice, PG&E will continue to provide electric transmission and
distribution services to all customers within its service territory.
During the transition period, all customers will be billed for electricity
<PAGE>
used, for transmission and distribution services, for PPPs, and for
recovery of transition costs through the nonbypassable CTC. As a result,
during the transition period, the overall electric rates of direct access
customers would vary from customers who choose PG&E bundled services
primarily to the extent that their direct access electricity price differs
from the PX price. Because the CTC is nonbypassable (customers will pay
the CTC regardless of whether they select direct access or not), PG&E does
not believe that direct access will have a material impact on PG&E's
ability to recover transition costs.
The revenue cycle services decision allows electricity providers to
choose the method of billing their customers and to choose whether to
provide their customers with metering. As related to the billing of direct
access customers, the customer's electricity provider can choose one of the
following three billing options: (1) the electricity provider could bill
the customer for the electricity provided and PG&E would separately bill
the customer for transmission and distribution services, including CTC and
PPP costs; (2) PG&E could provide the customer with one consolidated bill
for transmission and distribution services, including CTC and PPP costs,
and for the electricity supplied by the electricity provider; or (3) the
electricity provider could provide the customer with one consolidated bill
for the electricity provided and for transmission and distribution
services, including CTC and PPP costs, provided by PG&E.
Further, beginning in 1998, electricity providers may choose to provide
metering services to their large electricity customers (customers with
electricity demand of 20 kilowatts or more). And, beginning in 1999, these
providers may choose to provide metering services to all of their customers
regardless of size. The revenue cycle decision requires PG&E to separately
identify cost savings that would result when billing, metering, and related
services within PG&E's service territory are provided by another entity.
Once these cost savings, or credits, are approved by the CPUC and the
customer's energy supplier is providing billing and metering services, the
PG&E portion of the customer's bill would be reduced by the savings and the
electricity provider would charge for these services. To the extent that
these credits equate to PG&E's actual cost savings from reduced billing,
metering, and related services, PG&E does not expect a material adverse
impact on its or PG&E Corporation's financial positions or results of
operations.
Accounting for the Effects of Regulation:
- ----------------------------------------
PG&E accounts for the financial effects of regulation in accordance with
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation." This statement allows PG&E to
record certain regulatory assets and liabilities which would be included in
future rates and would not be recorded under generally accepted accounting
principles for nonregulated entities. In addition, SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of," requires that regulatory assets be written off
when they are no longer probable of recovery and that impairment losses be
recorded for long-lived assets when related future cash flows are less than
the carrying value of the assets.
In applying the provisions of SFAS No. 71, PG&E has accumulated
approximately $1.7 billion of regulatory assets attributable to electric
generation at June 30, 1997. The net investments in Diablo Canyon and the
other generation assets, including allocations of common plant, were $4.1
billion and $2.7 billion, respectively, at June 30, 1997. The net present
value of above-market QF power purchase obligations is estimated to be $5.3
billion at January 1, 1998, at an assumed market price of $0.025 per kWh
beginning in 1997 and escalating at 3.2 percent per year.
<PAGE>
PG&E believes that the restructuring legislation establishes a definitive
transition to the market-based pricing for electric generation that includes
recovery of the transition costs through a nonbypassable charge (the
competition transition charge or CTC). At the conclusion of the transition
period, PG&E believes it will be at risk to recover its generation costs
through market-based revenues.
As a result of California's electric industry restructuring and related
legislation, in 1996 the staff of the Securities and Exchange Commission
(SEC) began discussions with PG&E and other California utilities regarding
the appropriateness of the continued application of SFAS No. 71 for the
generation portion of the electric utilities' businesses as of January 1,
1997. Because of the importance of this issue to the electric utility
industry in the United States, the SEC referred the issue to the Emerging
Issues Task Force (EITF) of the Financial Accounting Standards Board
(FASB).
In its meeting on July 24, 1997, the EITF reached a consensus on EITF
Issue No. 97-4 "Deregulation of the Pricing of Electricity - Issues Related
to the Application of FASB Statements No. 71, Accounting for the Effects of
Certain Types of Regulation, and No. 101, Regulated Enterprises -
Accounting for the Discontinuation of Application of FASB Statement No. 71"
(EITF 97-4). The consensus will require PG&E to discontinue the
application of SFAS No. 71 for the generation portion of its operations as
of July 24, 1997, the effective date of EITF 97-4. The discontinuation of
application of SFAS No. 71 will not have a material effect on PG&E's
financial statements because EITF 97-4 requires that regulatory assets and
liabilities (both those in existence today and those created under the
terms of the transition plan) be allocated to the portion of the business
from which the source of the regulated cash flows are derived. Under the
terms of PG&E's transition cost recovery plan, approved by the CPUC in
1996, PG&E's generation related regulatory assets and liabilities,
including uncollected CTC, will be recovered through a CTC imposed on the
distribution customers during the transition period. EITF 97-4 will become
final upon approval of the minutes of the July 24 meeting, which is
expected in August 1997.
Given the current regulatory environment, PG&E's electric transmission
business and most areas of the distribution business are expected to remain
regulated and, as a result, PG&E will continue to apply the provisions of
SFAS No. 71. However, the CPUC's revenue cycle decision discussed above
allows electricity providers to provide their customers with billing and
metering services, and indicates that electricity providers may be allowed
to provide other distribution services (such as customer inquiries and
uncollectibles) in the future. Any discontinuance of SFAS No. 71 for these
portions of PG&E's electric distribution business is not expected to have a
material adverse impact on the Corporation's or PG&E's financial position or
results of operations.
GAS INDUSTRY RESTRUCTURING:
On August 1, 1997, the CPUC unanimously adopted a final decision approving
the Gas Accord Settlement (Accord), which was submitted in 1996 for CPUC
approval. The Accord establishes California as a national leader in the
move toward restructuring gas distribution services and making them more
competitive. The Accord is a collaborative settlement by PG&E and more than
25 gas industry participants and government regulatory agencies. The Accord
will increase the opportunity for residential customers to choose the gas
supplier of their choice, change the pricing and regulatory structure for
transporting natural gas within California, establish an incentive mechanism
to set the standard of reasonableness for PG&E's core gas purchases, and
offer more transportation services and choices to natural gas customers.
<PAGE>
The Accord will also resolve numerous major regulatory gas proceedings in
which PG&E and many other parties are involved.
Specific provisions of the decision include the following:
- The decision affirms the CPUC's 1994 finding that the decision to
construct Line 401 (the California segment of the PG&E/PGT pipeline that
extends from the Canadian border to Kern River Station in Southern
California) was reasonable based on PG&E's management's knowledge at the
time. The decision accepts the Accord's proposal to set rates for Line 401
based on total capital costs of $736 million.
- The decision approves the Rule 1 settlement that PG&E reached with the
CPUC Consumer Services Division on July 1, 1997. The issue related to
whether or not PG&E had misled the CPUC in violation of Rule 1, the CPUC's
Code of Ethics, in connection with responding to certain discovery requests
in the CPUC proceeding to determine whether the decision to construct Line
401 was reasonable.
- The decision adopts a discounting rule. Under this discounting rule,
whenever PG&E offers a rate discount on its in-state pipeline (Line 401)
that accesses Canadian suppliers, it must also offer the same discount on
pipelines transporting Southwestern and in-state gas production.
- The decision approves the core procurement incentive mechanisms (CPIM)
proposed in the Accord to replace the traditional reasonableness review
proceedings of PG&E's gas procurement costs for the period 1994 through
2002.
- The decision approves the Accord's proposal that PG&E forgo recovery of
100 percent and 50 percent of the Interstate Transition Cost Surcharge
(ITCS) amounts allocated for collection from its residential and smaller
commercial (core) and industrial and larger commercial (noncore) customers,
respectively. (ITCS costs are the difference between fixed demand charges
PG&E pays under gas transportation contracts with interstate pipeline
companies for the reservation of interstate pipeline capacity that PG&E no
longer uses to serve noncore customers and the revenues PG&E obtains from
brokering that capacity.)
- Finally, the decision states that the CPUC's intention to implement the
rates and other provisions of the Accord throughout the Accord period is
subject to the CPUC's overreaching policy goals and the CPUC's decisions
reached in the CPUC's natural gas industry strategic plan to produce a more
competitive gas market.
As of June 30, 1997, approximately $490 million had been reserved
relating to these gas regulatory issues and capacity commitments. As
result, the Corporation believes that the decision will not have a material
adverse impact on its or PG&E's financial position or results of operations.
ACQUISITIONS AND SALES:
On April 2, 1997, Bechtel Enterprises, Inc. (Bechtel) acquired Enterprises'
interest in International Generating Company, Ltd. (InterGen), a joint
venture between Enterprises and Bechtel. The sale resulted in an after-tax
gain of approximately $110 million, which was recorded in the second
quarter of 1997.
On June 26, 1997, the Corporation announced its agreement to acquire
Bechtel's interests in U.S. Generating Company (USGen), operations and
maintenance affiliate U.S. Operating Services Company, and power marketing
affiliate USGen Power Services, L.P., by redemption of Bechtel's interests
<PAGE>
in such partnerships. In addition, the Corporation has agreed to purchase
Bechtel's interest in certain independent power projects currently owned by
Bechtel and PG&E Corporation (through Enterprises) or by Bechtel, PG&E
Corporation, and various third parties. USGen is a joint venture formed by
PG&E and Bechtel in 1989 to develop, own, and manage independent power
production facilities in North America. The purchase is expected to be
completed by December 31, 1997.
In October 1996, PG&E announced it would sell four of its California
fossil-fueled power plants. The combined net book value of these plants is
approximately $380 million. These plants generate approximately 10 percent
of PG&E's total electric sales. PG&E's proposal for the sale of these
plants is currently under consideration by the CPUC.
In June 1997, PG&E announced its plans, subject to CPUC approval, to sell
an additional three of its California fossil-fueled power plants and its
geothermal power plant. The four additional plants identified for sale by
PG&E generate approximately eight percent of PG&E's total electric sales.
The combined net book value for the four plants is approximately $660
million. PG&E intends to file its plan for the sale of these power plants
with the CPUC later this year and will seek to sign sales agreements with
buyers by the end of 1998.
PG&E has proposed that any loss incurred on the sale of the eight plants
would be recovered as a transition cost. Likewise, any gain on the sale
would offset other transition costs. Accordingly, PG&E does not expect any
adverse impact on its results of operations from the sale of these plants.
On July 31, 1997, the Corporation completed its acquisition of Valero
Energy Corporation (Valero) (which was renamed PG&E Gas Transmission, Texas
Corporation), including its natural gas and natural gas liquids business,
but excluding its refining operations. The outstanding shares of Valero
common stock were converted into PG&E Corporation common stock for a total
issuance of approximately 31,000,000 shares. The purchase price of Valero
was approximately $771 million, and approximately $800 million in long-term
debt was assumed. The acquisition was accounted for as a purchase.
On August 6, 1997, the Corporation announced that USGen (through a
special purpose entity wholly owned by PG&E Corporation) had agreed to
acquire a portfolio of non-nuclear electric generating assets and power
supply contracts from the New England Electric System for approximately
$1.59 billion, plus $85 million to cover early retirement and severance
costs. Including fuel, other inventories, and transaction costs, financing
requirements are expected to total approximately $1.75 billion. The assets
to be acquired contain a mix of hydro, coal, oil, and gas generation and
represent the second largest non-nuclear electric generation portfolio in
New England, comprising approximately 17 percent of New England's total
installed generating capacity. The acquisition of these assets, which is
subject to approval of the FERC and state regulators, among other
conditions, is expected to be completed in 1998.
<PAGE>
RESULTS OF OPERATIONS:
The Corporation's results of operations were derived primarily from five
business lines: Utility (consisting of PG&E, including Diablo Canyon), PG&E
Gas Transmission Corporation including PGT, PG&E Energy Trading Corporation,
PG&E Energy Services Corporation, and Enterprises including its interest in
USGen.
The results of operations for the parent company, PG&E Corporation, alone
are not material for separate disclosure as a business line and have been
allocated among the business lines based primarily on their percentage of
operating revenues. The results of operations for all business lines other
than Utility are not material for separate disclosure and have been shown as
Other in the table below. The results of operations for the three- and six-
months ended June 30, 1997 and 1996, and total assets at June 30, 1997 and
1996, are reflected in the following table and discussed below:
<TABLE>
PG&E Corporation
(in millions, except per share amounts)
<CAPTION>
Utility Other Total
--------- ------- -------
<S> <C> <C> <C>
For the three months ended
June 30, 1997
Operating revenues $ 2,279 $ 804 $ 3,083
Operating expenses 1,910 802 2,712
-------- -------- --------
Operating income
before income taxes 369 2 371
Net income 121 72 193
Earnings per common share 0.30 0.19 0.49
June 30, 1996
Operating revenues 2,060 79 2,139
Operating expenses 1,792 58 1,850
-------- -------- --------
Operating income
before income taxes 268 21 289
Net income 90 13 103
Earnings per common share 0.22 0.03 0.25
For the six months ended
June 30, 1997
Operating revenues $ 4,553 $ 1,896 $ 6,449
Operating expenses 3,741 1,873 5,614
-------- -------- --------
Operating income
before income taxes 812 23 835
Net income 284 81 365
Earnings per common share 0.71 0.20 0.91
Total assets at June 30 $ 23,531 $ 3,144 $ 26,675
June 30, 1996
Operating revenues 4,224 163 4,387
Operating expenses 3,422 103 3,525
-------- -------- -------
Operating income
before income taxes 802 60 862
Net income 321 35 356
Earnings per common share 0.78 0.08 0.86
Total assets at June 30 $ 23,807 $ 1,951 $ 25,758
</TABLE>
<PAGE>
Common Stock Dividend:
- ---------------------
PG&E Corporation's common stock dividend is based on a number of financial
considerations, including sustainability, financial flexibility, and
competitiveness with investment opportunities of similar risk. PG&E
Corporation's current quarterly common stock dividend is $.30 per common
share, which corresponds to an annualized dividend of $1.20 per common
share. PG&E Corporation has identified a dividend payout ratio objective
(dividends declared divided by earnings available for common stock) of
between 50 and 65 percent (based on earnings exclusive of nonrecurring
adjustments).
PG&E's formation of a holding company was approved by the CPUC subject
to a number of conditions, including the requirement that, on average, PG&E
must maintain its CPUC-authorized capital structure. In the event that
PG&E fails to maintain, on average, the CPUC-authorized capital structure,
PG&E's ability to pay dividends to PG&E Corporation may be limited.
However, if an adverse financial event reduces PG&E's equity ratio by one
percent or more, the CPUC requires PG&E to request a waiver of this average
capital structure requirement. PG&E shall not be considered in violation
of this requirement by the CPUC during the period the waiver is pending
resolution.
Earnings Per Common Share:
- -------------------------
Earnings per common share for the three- and six-month periods ended June
30, 1997, increased as compared to the same periods in 1996. This
increase is due to a reduction in the number of common shares outstanding
and the activity discussed below.
Utility:
- --------
Utility operating revenues increased for the three- and six-months ended
June 30, 1997, as compared with the same periods in 1996. This increase is
due to the revisions to the Diablo Canyon ratemaking structure discussed in
Electric Industry Restructuring above. These revisions resulted in fixed
sunk cost revenue recovery during the current scheduled outage, while no
revenue recovery was provided during the previous scheduled outage. There
was also an increase in energy cost revenues to recover energy cost
increases in both natural gas prices and sales volume. Under energy cost
recovery mechanisms, energy cost revenues generally equal energy cost
expense and, thus, energy cost increases do not affect operating income.
Utility operating expenses increased overall due to an increase in
Diablo Canyon depreciation associated with the new Diablo Canyon ratemaking
structure. In comparison to the second quarter 1996, these increases were
offset by a decrease in administrative and general expenses due to a
litigation reserve which was recorded in the second quarter of 1996.
Other Lines of Business:
- ------------------------
Other lines of business operating revenues for the three- and six-months
ended June 30, 1997, as compared with the same periods in 1996 increased
primarily due to the acquisitions of Energy Source (now known as PG&E
Energy Trading Corporation) in December 1996 and Teco Pipeline Company (now
known as PG&E Gas Transmission Teco, Inc.) in January 1997. Revenues and
expenses associated with these acquisitions are approximately $284 million
per month.
<PAGE>
Other lines of business other income and expense increased primarily due
to a gain on the sale of Enterprises' interest in InterGen of approximately
$110 million, which was offset by write-offs of nonregulated investments of
approximately $41 million.
LIQUIDITY AND CAPITAL RESOURCES:
Sources of Capital:
- ------------------
The Corporation's capital requirements are funded from cash provided by
operations and, to the extent necessary, external financing. The
Corporation's policy is to finance its assets with a capital structure that
minimizes financing costs, maintains financial flexibility, and, with
regard to PG&E, complies with regulatory guidelines. Based on cash
provided from operations and its capital requirements, the Corporation may
repurchase equity and long-term debt in order to manage the overall balance
of its capital structure.
In June 1997, PG&E entered into a $500 million temporary credit facility
which will be used to meet PG&E's cash needs until the placement of the rate
reduction bonds, which are described below. In August 1997, PG&E
Corporation entered into a $500 million temporary credit facility for
general corporate purposes. Both of these credit facilities will expire 364
days from the date they were established. The Corporation's short-term
borrowings increased $848 million during the six-month period ended June 30,
1997.
During the six-month period ended June 30, 1997, PG&E Corporation issued
$344 million of common stock. Of this common stock, $319 million was
issued in connection with the acquisition of Teco Pipeline Company and its
subsidiaries. The remaining $25 million was issued through the Dividend
Reinvestment Plan and the Stock Option Plan. Also during the six-month
period ended June 30, 1997, PG&E Corporation repurchased $575 million of
its common stock on the open market.
Long-term debt matured, redeemed, or repurchased during the six-months
ended June 30, 1997, amounted to $345 million. Of this amount, $58 million
related to PG&E's redemption of its 12% Eurobond debentures, $167 million
related to PG&E's repurchase of its mortgage bonds, and $45 million related
to PG&E's refinancing of its fixed-rate pollution control bonds with
variable rate debt. The remaining $75 million related to the maturity of
long-term debt.
As discussed above in "Electric Industry Restructuring," to achieve the
10 percent rate reduction for residential and small commercial customers,
the electric industry restructuring legislation authorizes utilities to
finance a portion of their transition costs with "rate reduction bonds." In
May 1997, PG&E filed an application with the CPUC for the issuance of an
estimated $3.1 billion of these bonds by means of a special purpose entity.
In August 1997, the CPUC issued a proposed decision (PD) which would
authorize PG&E to issue the bonds substantially as proposed. A final
decision is expected in September 1997. If the PD is issued as drafted,
PG&E expects these bonds would be issued in the fourth quarter of 1997. The
special purpose entity will acquire from PG&E the right to be paid the
revenues from a separate tariff to recover principal, interest, and issuance
costs over the life of the bonds from residential and small commercial
customers. The bonds will be secured by the future revenue from the
separate tariff and not by PG&E's assets. However, in accordance with a SEC
ruling, once issued, the bonds would be reflected on PG&E's balance sheet.
<PAGE>
Cost of Capital Application:
- ---------------------------
In May 1997, PG&E filed an application with the CPUC requesting the
following cost of capital for 1998:
Capital Weighted
Ratio Cost/Return Cost/Return
-------- ------------ -----------
Long-term debt 46.20% 7.37% 3.40%
Preferred stock 5.80 6.65 0.39
Common equity 48.00 12.25 5.88
-----------
Total return on
average utility rate base 9.67%
===========
The proposed cost of common equity is 0.65 percentage points higher than
the 11.6 percent adopted for 1997. This increase reflects the level of
business and regulatory risks PG&E now faces. If adopted, the proposed
cost of capital would increase PG&E's 1998 gas revenue requirement by $13
million. Consistent with the electric rate freeze, PG&E's proposed cost of
capital would not change electric rates.
Environmental Matters:
- ---------------------
PG&E assesses, on an ongoing basis, compliance with laws and regulations
related to hazardous substance remediation. At June 30, 1997, PG&E had an
accrued liability of $221 million for remediation costs at sites, including
fossil-fuel power plants, where such costs are probable and quantifiable.
The costs at identified sites may be as much as $489 million if, among
other things, other potentially responsible parties are not financially
able to contribute to these costs or identifiable possible outcomes change.
PG&E will seek recovery of prudently incurred compliance costs through
ratemaking procedures approved by the CPUC. PG&E had recorded regulatory
assets at June 30, 1997, of $152 million for recovery of these costs in
future rates. Additionally, PG&E will seek recovery of costs from
insurance carriers and from other third parties. (See Note 5 of Notes to
Consolidated Financial Statements.)
Legal Matters:
- --------------
In the normal course of business, both PG&E and the Corporation are named
as parties in a number of claims and lawsuits. Substantially all of these
have been litigated or settled with no material adverse impact on PG&E's or
the Corporation's results of operations or financial position. See Note 5
to the Consolidated Financial Statements for further discussion of
significant pending legal matters.
<PAGE>
PART II. OTHER INFORMATION
---------------------------
Item 1. Legal Proceedings
-----------------
A. Antitrust Litigation
As previously reported in PG&E Corporation's (the Corporation)
and Pacific Gas and Electric Company's (PG&E) Annual Report on Form
10-K for the year ended December 31, 1996, in December 1993, the
County of Stanislaus and a residential customer of PG&E filed a class
action lawsuit in United States District Court, Eastern District of
California against PG&E and Pacific Gas Transmission Company (PGT)
relating to PGT's Canadian gas purchases. On December 18, 1995, the
District Court dismissed the plaintiffs' amended complaint with
prejudice. The plaintiffs appealed the District Court's dismissal of
their complaint to the Ninth Circuit Court of Appeals. On May 29,
1997, the Ninth Circuit Court of Appeals affirmed the District
Court's dismissal of the plaintiffs' complaint. The plaintiffs
subsequently filed a motion for reconsideration of the appellate
decision. On July 15, 1997, the Ninth Circuit Court of Appeals
denied the plaintiffs' motion for reconsideration.
The Corporation believes that the ultimate outcome of this matter
will not have a material adverse impact on its or PG&E's financial
position or results of operation.
B. Norcen Litigation
On June 27, 1997, PGT and PG&E entered into an agreement with Norcen
Energy Resources Limited (Norcen Energy) and Norcen Marketing
Incorporated (Norcen Marketing) to settle the litigation filed
against PGT and PG&E by Norcen Energy and Norcen Marketing in the
United States District Court, Northern District of California, on
March 17, 1994. As has been previously reported in PG&E
Corporation's and PG&E's Annual Report on Form 10-K for the year
ended December 31, 1996, Norcen Energy's and Norcen Marketing's
complaint against PGT and PG&E alleged that PGT and PG&E wrongfully
induced Norcen Energy and Norcen Marketing to enter into a 30-year
contract with PGT for firm transportation service by concealing legal
action taken by PG&E before the CPUC two days before Norcen
Marketing's contract with PGT became binding. The complaint also
alleged certain breaches of representations made to Norcen Marketing
and various federal and state antitrust, contractual and other
claims, and sought rescission, restitution and recovery of
unspecified damages.
The settlement of this matter will not have a material adverse impact
on the Corporation's or PG&E's financial position or results of
operation.
<PAGE>
C. California Attorney General Investigation and Diablo Canyon
Environmental Litigation
As previously reported in PG&E Corporation's and PG&E's Annual Report
on Form 10-K for the year ended December 31, 1996, in February 1995,
the California Attorney General (AG) initiated an investigation to
determine whether PG&E and its consultant, Tenera, Inc., (Tenera)
violated the Federal Clean Water Act and the California Water Code in
connection with a 1988 study (1988 Study) of the cooling water intake
system at the Diablo Canyon Power Plant (Diablo Canyon). The United
States Department of Justice (DOJ) later joined the AG's
investigation. On May 2, 1997, PG&E, the AG, and the DOJ, entered
into a settlement agreement, subject to court approval, to resolve
this matter. On May 27, 1997, this settlement agreement was filed in
United States District Court, Northern District of California, for
approval.
Further, as previously reported in PG&E Corporation's and PG&E's
Annual Report on Form 10-K for the year ended December 31, 1996, the
League for Coastal Protection (Coastal League) filed two lawsuits
involving the 1988 study. The first lawsuit was filed in San
Francisco County Superior Court in October 1995, against PG&E and its
consultant, Tenera, and alleged violations of the California Business
and Professions Code in connection with the 1988 Study. The Coastal
League sought an unspecified amount of damages related to restitution
or disgorgement of improper or excessive profits, punitive damages,
injunctive relief and attorneys' fees. The Coastal League filed a
second lawsuit in the United States District Court for the Northern
District of California in April 1996, against PG&E and Tenera,
alleging violations of the federal Clean Water Act in connection with
the 1988 Study. The Coastal League sought a judgment that PG&E
violated its discharge permit for Diablo Canyon, revocation of the
permit, an order requiring restoration of the marine environment, an
unspecified amount of civil penalties and recovery of its litigation
and attorneys' fees.
As previously reported in PG&E Corporation's and PG&E's Annual Report
on Form 10-K for the year ended December 31, 1996), in April 1996,
PG&E also received a copy of a complaint filed in a third case
involving the 1988 Study. In this case, John W. Carter (Carter)
alleged on behalf of himself and the United States and the State of
California that PG&E, Tenera, and certain of their employees violated
the federal and state False Claims Acts by filing an incomplete
report in 1988 (i.e., the 1988 Study) and failing to correct it. The
United States and the State of California declined to prosecute this
action. The plaintiffs sought civil penalties, treble damages, a
separate payment to Carter under the False Claims Acts and attorneys'
fees.
On May 2, 1997, PG&E also reached a settlement agreement with the
Coastal League and Carter which is contingent on the district court's
approval of the settlement agreement with the AG and the DOJ. Under
the terms of the two settlement agreements, PG&E admits to no
liability but will pay an aggregate of $15.6 million, plus interest,
<PAGE>
including $7.1 million for civil penalties, and $6.19 million for
environmental projects.
The settlement of these matters on the terms agreed to will not have
a material adverse impact on the Corporation's or PG&E's financial
position or results of operation.
Item 5. Other Information
-----------------
A. Ratio of Earnings to Fixed Charges and Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
PG&E's earnings to fixed charges ratio for the six months ended June
30, 1997 was 2.75. PG&E's earnings to combined fixed charges and
preferred stock dividends ratio for the six months ended June 30,
1997 was 2.55. 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
PG&E's various classes of debt and first preferred stock outstanding.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 3 Bylaws of Pacific Gas and Electric
Company amended as of June 1, 1997
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
Exhibit 27.1 Financial Data Schedule for the six months ended
June 30, 1997 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the six months ended
June 30, 1997 for PG&E
<PAGE>
(b) Reports on Form 8-K during the second quarter of 1997 and
through the date hereof (1):
1. April 18, 1997
Item 5. Other Events
A. Performance Incentive Plan -- Year-to-Date Financial
Results
B. Application of SFAS 71
C. Gas Accord
D. Common Stock Repurchase Program
E. Ratio of Earnings to Fixed Charges and Ratio of Earnings
to Combined Fixed Charges and Preferred Stock Dividends
Item 7. Financial Statements, Pro Forma Financial
Information and Exhibits
(c) Exhibits
12.1 Computation of Ratio of Earnings to Fixed
Charges (12/31/96)
12.2 Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
(12/31/96)
2. May 9, 1997
Item 5. Other Events
A. Electric Industry Restructuring
3. May 22, 1997
Item 5. Other Events
A. Electric Industry Restructuring
B. Changes in Management
4. June 24, 1997
Item 5. Other Events
A. Electric Industry Restructuring
B. Gas Accord
C. Changes in Management
5. June 26, 1997
Item 5. Other Events
A. Acquisition
6. July 22, 1997
Item 5. Other Events
A. Performance Incentive Plan - Year to Date Financial
Results
7. August 6, 1997
Item 5. Other Events
A. Acquisitions
B. Gas Accord
- -----------------------------
(1) Unless otherwise noted, all Reports on Form 8-K were filed under
both Commission File Number 1-12609 (PG&E Corporation) and
Commission File Number 1-2348 (PG&E)
<PAGE>
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
and
PACIFIC GAS AND ELECTRIC COMPANY
CHRISTOPHER P. JOHNS
August 13, 1997 By______________________________
CHRISTOPHER P. JOHNS
Vice President and Controller
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company)
<PAGE>
EXHIBIT INDEX
Exhibit No. Description of Exhibit
Exhibit 3 Bylaws of Pacific Gas and Electric
Company amended as of June 1, 1997
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
Exhibit 27.1 Financial Data Schedule for the six months ended
June 30, 1997 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the six months ended
June 30, 1997 for PG&E
<PAGE>
Bylaws
of
Pacific Gas and Electric Company
as amended as of June 1, 1997
Article I.
SHAREHOLDERS.
1. Place of Meeting. All meetings of the shareholders
shall be held at the office of the Corporation in the City and
County of San Francisco, State of California, or at such other
place within the State of California as may be designated by the
Board of Directors.
2. Annual Meetings. The annual meeting of shareholders
shall be held each year on a date and at a time designated by the
Board of Directors.
Written notice of the annual meeting shall be given not less
than ten (or, if sent by third-class mail, thirty) nor more than
sixty days prior to the date of the meeting to each shareholder
entitled to vote thereat. The notice shall state the place, day,
and hour of such meeting, and those matters which the Board, at
the time of mailing, intends to present for action by the
shareholders.
Notice of any meeting of the shareholders shall be given by
mail or telegraphic or other written communication, postage
prepaid, to each holder of record of the stock entitled to vote
thereat, at his address, as it appears on the books of the
Corporation.
3. Special Meetings. Special meetings of the shareholders
shall be called by the Secretary or an Assistant Secretary at any
time on order of the Board of Directors, the Chairman of the
Board, the Vice Chairman of the Board, the Chairman of the
Executive Committee, or the President. Special meetings of the
shareholders shall also be called by the Secretary or an
Assistant Secretary upon the written request of holders of shares
entitled to cast not less than ten percent of the votes at the
meeting. Such request shall state the purposes of the meeting,
and shall be delivered to the Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee,
the President or the Secretary.
<PAGE>
A special meeting so requested shall be held on the date
requested, but not less than thirty-five nor more than sixty days
after the date of the original request. Written notice of each
special meeting of shareholders, stating the place, day, and hour
of such meeting and the business proposed to be transacted
thereat, shall be given in the manner stipulated in Article I,
Section 2, Paragraph 3 of these Bylaws within twenty days after
receipt of the written request.
4. Attendance at Meetings. At any meeting of the
shareholders, each holder of record of stock entitled to vote
thereat may attend in person or may designate an agent or a
reasonable number of agents, not to exceed three to attend the
meeting and cast votes for his shares. The authority of agents
must be evidenced by a written proxy signed by the shareholder
designating the agents authorized to attend the meeting and be
delivered to the Secretary of the Corporation prior to the
commencement of the meeting.
5. No Cumulative Voting. No shareholder of the Corporation
shall be entitled to cumulate his or her voting power.
Article II.
DIRECTORS.
1. Number. The Board of Directors shall consist of
seventeen (17) directors.
2. Powers. The Board of Directors shall exercise all the
powers of the Corporation except those which are by law, or by
the Articles of Incorporation of this Corporation, or by the
Bylaws conferred upon or reserved to the shareholders.
3. Executive Committee. There shall be an Executive
Committee of the Board of Directors consisting of the Chairman of
the Committee, the Chairman of the Board, if these offices be
filled, the President, and four Directors who are not officers of
the Corporation. The members of the Committee shall be elected,
and may at any time be removed, by a two-thirds vote of the whole
Board.
The Executive Committee, subject to the provisions of law,
may exercise any of the powers and perform any of the duties of
the Board of Directors; but the Board may by an affirmative vote
of a majority of its members withdraw or limit any of the powers
of the Executive Committee.
The Executive Committee, by a vote of a majority of its
members, shall fix its own time and place of meeting, and shall
prescribe its own rules of procedure. A quorum of the Committee
for the transaction of business shall consist of three members.
4. Time and Place of Directors' Meetings. Regular meetings
of the Board of Directors shall be held on such days and at such
<PAGE>
times and at such locations as shall be fixed by resolution of
the Board, or designated by the Chairman of the Board or, in his
absence, the Vice Chairman of the Board, or the President of the
Corporation and contained in the notice of any such meeting.
Notice of meetings shall be delivered personally or sent by mail
or telegram at least seven days in advance.
5. Special Meetings. The Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee,
the President, or any five directors may call a special meeting
of the Board of Directors at any time. Notice of the time and
place of special meetings shall be given to each Director by the
Secretary. Such notice shall be delivered personally or by
telephone to each Director at least four hours in advance of such
meeting, or sent by first-class mail or telegram, postage
prepaid, at least two days in advance of such meeting.
6. Quorum. A quorum for the transaction of business at any
meeting of the Board of Directors shall consist of six members.
7. Action by Consent. Any action required or permitted to
be taken by the Board of Directors may be taken without a meeting
if all Directors individually or collectively consent in writing
to such action. Such written consent or consents shall be filed
with the minutes of the proceedings of the Board of Directors.
8. Meetings by Conference Telephone. Any meeting, regular
or special, of the Board of Directors or of any committee of the
Board of Directors, may be held by conference telephone or
similar communication equipment, provided that all Directors
participating in the meeting can hear one another.
Article III.
OFFICERS.
1. Officers. The officers of the Corporation shall be a
Chairman of the Board, a Vice Chairman of the Board, a Chairman
of the Executive Committee (whenever the Board of Directors in
its discretion fills these offices), a President, one or more
Vice Presidents, a Secretary and one or more Assistant
Secretaries, a Treasurer and one or more Assistant Treasurers, a
General Counsel, a General Attorney (whenever the Board of
Directors in its discretion fills this office), and a Controller,
all of whom shall be elected by the Board of Directors. The
Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, and the President shall be
members of the Board of Directors.
2. Chairman of the Board. The Chairman of the Board, if
that office be filled, shall preside at all meetings of the
shareholders, of the Directors, and of the Executive Committee in
the absence of the Chairman of that Committee. He shall be the
chief executive officer of the Corporation if so designated by
the Board of
<PAGE>
Directors. He shall have such duties and
responsibilities as may be prescribed by the Board of Directors
or the Bylaws. The Chairman of the Board shall have authority to
sign on behalf of the Corporation agreements and instruments of
every character, and in the absence or disability of the
President, shall exercise his duties and responsibilities.
3. Vice Chairman of the Board. The Vice Chairman of the
Board, if that office be filled, shall have such duties and
responsibilities as may be prescribed by the Board of Directors,
the Chairman of the Board, or the Bylaws. He shall be the chief
executive officer of the Corporation if so designated by the
Board of Directors. In the absence of the Chairman of the Board,
he shall preside at all meetings of the Board of Directors and of
the shareholders; and, in the absence of the Chairman of the
Executive Committee and the Chairman of the Board, he shall
preside at all meetings of the Executive Committee. The Vice
Chairman of the Board shall have authority to sign on behalf of
the Corporation agreements and instruments of every character.
4. Chairman of the Executive Committee. The Chairman of
the Executive Committee, if that office be filled, shall preside
at all meetings of the Executive Committee. He shall aid and
assist the other officers in the performance of their duties and
shall have such other duties as may be prescribed by the Board of
Directors or the Bylaws.
5. President. The President shall have such duties and
responsibilities as may be prescribed by the Board of Directors,
the Chairman of the Board, or the Bylaws. He shall be the chief
executive officer of the Corporation if so designated by the
Board of Directors. If there be no Chairman of the Board, the
President shall also exercise the duties and responsibilities of
that office. The President shall have authority to sign on
behalf of the Corporation agreements and instruments of every
character.
6. Vice Presidents. Each Vice President shall have such
duties and responsibilities as may be prescribed by the Board of
Directors, the Chairman of the Board, the Vice Chairman of the
Board, the President, or the Bylaws. Each Vice President's
authority to sign agreements and instruments on behalf of the
Corporation shall be as prescribed by the Board of Directors.
The Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, or the President may confer a special
title upon any Vice President.
7. Secretary. The Secretary shall attend all meetings of
the Board of Directors and the Executive Committee, and all
meetings of the shareholders, and he shall record the minutes of
all proceedings in books to be kept for that purpose. He shall
be responsible for maintaining a proper share register and stock
transfer books for all classes of shares issued by the
Corporation. He shall give, or cause to be given, all notices
required either by law or the Bylaws. He shall keep the seal of
the Corporation in safe custody, and shall affix the seal of the
Corporation to any instrument requiring it and shall attest the
same by his signature.
<PAGE>
The Secretary shall have such other duties as may be
prescribed by the Board of Directors, the Chairman of the Board,
the Vice Chairman of the Board, the President, or the Bylaws.
The Assistant Secretaries shall perform such duties as may be
assigned from time to time by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the
President, or the Secretary. In the absence or disability of the
Secretary, his duties shall be performed by an Assistant
Secretary.
8. Treasurer. The Treasurer shall have custody of all
moneys and funds of the Corporation, and shall cause to be kept
full and accurate records of receipts and disbursements of the
Corporation. He shall deposit all moneys and other valuables of
the Corporation in the name and to the credit of the Corporation
in such depositaries as may be designated by the Board of
Directors or any employee of the Corporation designated by the
Board of Directors. He shall disburse such funds of the
Corporation as have been duly approved for disbursement.
The Treasurer shall perform such other duties as may from
time to time be prescribed by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws.
The Assistant Treasurer shall perform such duties as may be
assigned from time to time by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the
President, or the Treasurer. In the absence or disability of the
Treasurer, his duties shall be performed by an Assistant
Treasurer.
9. General Counsel. The General Counsel shall be
responsible for handling on behalf of the Corporation all
proceedings and matters of a legal nature. He shall render
advice and legal counsel to the Board of Directors, officers, and
employees of the Corporation, as necessary to the proper conduct
of the business. He shall keep the management of the Corporation
informed of all significant developments of a legal nature
affecting the interests of the Corporation.
The General Counsel shall have such other duties as may from
time to time be prescribed by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws.
10. Controller. The Controller shall be responsible
for maintaining the accounting records of the Corporation and for
preparing necessary financial reports and statements, and he
shall properly account for all moneys and obligations due the
Corporation and all properties, assets, and liabilities of the
Corporation. He shall render to the officers such periodic
reports covering the result of operations of the Corporation as
may be required by them or any one of them.
<PAGE>
The Controller shall have such other duties as may from time
to time be prescribed by the Board of Directors, the Chairman of
the Board, the Vice Chairman of the Board, the President, or the
Bylaws. He shall be the principal accounting officer of the
Corporation, unless another individual shall be so designated by
the Board of Directors.
Article IV.
MISCELLANEOUS.
1. Record Date. The Board of Directors may fix a time in
the future as a record date for the determination of the
shareholders entitled to notice of and to vote at any meeting of
shareholders, or entitled to receive any dividend or
distribution, or allotment of rights, or to exercise rights in
respect to any change, conversion, or exchange of shares. The
record date so fixed shall be not more than sixty nor less than
ten days prior to the date of such meeting nor more than sixty
days prior to any other action for the purposes for which it is
so fixed. When a record date is so fixed, only shareholders of
record on that date are entitled to notice of and to vote at the
meeting, or entitled to receive any dividend or distribution, or
allotment of rights, or to exercise the rights, as the case may
be.
2. Transfers of Stock. Upon surrender to the Secretary or
Transfer Agent of the Corporation of a certificate for shares
duly endorsed or accompanied by proper evidence of succession,
assignment, or authority to transfer, and payment of transfer
taxes, the Corporation shall issue a new certificate to the
person entitled thereto, cancel the old certificate, and record
the transaction upon its books. Subject to the foregoing, the
Board of Directors shall have power and authority to make such
rules and regulations as it shall deem necessary or appropriate
concerning the issue, transfer, and registration of certificates
for shares of stock of the Corporation, and to appoint and remove
Transfer Agents and Registrars of transfers.
3. Lost Certificates. Any person claiming a certificate of
stock to be lost, stolen, mislaid, or destroyed shall make an
affidavit or affirmation of that fact and verify the same in such
manner as the Board of Directors may require, and shall, if the
Board of Directors so requires, give the Corporation, its
Transfer Agents, Registrars, and/or other agents a bond of
indemnity in form approved by counsel, and in amount and with
such sureties as may be satisfactory to the Secretary of the
Corporation, before a new certificate may be issued of the same
tenor and for the same number of shares as the one alleged to
have been lost, stolen, mislaid, or destroyed.
<PAGE>
Article V.
AMENDMENTS.
1. Amendment by Shareholders. Except as otherwise provided
by law, these Bylaws, or any of them, may be amended or repealed
or new Bylaws adopted by the affirmative vote of a majority of
the outstanding shares entitled to vote at any regular or special
meeting of the shareholders.
2. Amendment by Directors. To the extent provided by law,
these Bylaws, or any of them, may be amended or repealed or new
Bylaws adopted by resolution adopted by a majority of the members
of the Board of Directors.
<PAGE>
<TABLE>
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
<CAPTION>
- ----------------------------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
-------------------- ------------------------
(in thousands, except per share amounts) 1997 1996 1997 1996
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income for calculating EPS for
Statement of Consolidated Income $ 192,905 $ 103,502 $ 365,409 $ 355,928
========== ========== ========== ==========
Average common shares outstanding 397,677 415,125 403,072 414,738
========== ========== ========== ==========
EPS as shown in the Statement of
Consolidated Income $ 0.49 $ 0.25 $ 0.91 $ 0.86
========== ========== ========== ==========
PRIMARY EPS (1)
Net income for calculating primary EPS $ 192,905 $ 103,502 $ 365,409 $ 355,928
========== ========== ========== ==========
Average common shares outstanding 397,677 415,125 403,072 414,738
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from
such exercise (at average market price) 141 8 108 20
---------- ---------- ---------- ----------
Average common shares outstanding as
adjusted 397,818 415,133 403,180 414,758
========== ========== ========== ==========
Primary EPS $ 0.49 $ 0.25 $ 0.91 $ 0.86
========== ========== ========== ==========
FULLY DILUTED EPS (1)
Net income for calculating fully diluted EPS $ 192,905 $ 103,502 $ 365,409 $ 355,928
========== ========== ========== ==========
Average common shares outstanding 397,677 415,125 403,072 414,738
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from such
exercise (at the greater of average or
ending market price) 196 9 196 20
---------- ---------- ---------- ----------
Average common shares outstanding as
adjusted 397,873 415,134 403,268 414,758
========== ========== ========== ==========
Fully diluted EPS $ 0.49 $ 0.25 $ 0.91 $ 0.86
========== ========== ========== ==========
- ----------------------------------------------------------------------------------------------
<FN>
(1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K.
This presentation is not required by Accounting Principles Board Opinion No. 15, because it
results in dilution of less than 3%.
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Six Months Year ended December 31,
Ended -------------------------------------------------------
(dollars in thousands) 06/30/97 1996 1995 1994 1993 1992
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $302,467 $ 755,209 $1,338,885 $1,007,450 $1,065,495 $1,170,581
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates - 2,488 3,820 (2,764) 6,895 (3,349)
Income tax expense 245,107 554,994 895,289 836,767 901,890 895,126
Net fixed charges 311,694 683,393 715,975 730,965 821,166 802,198
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $ 859,268 $1,996,084 $2,953,969 $2,572,418 $2,795,446 $2,864,556
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 246,038 $ 580,510 $ 627,375 $ 651,912 $ 731,610 $ 739,279
Interest on short-
term borrowings 52,841 75,310 83,024 77,295 87,819 61,182
Interest on capital
leases 965 3,508 2,735 1,758 1,737 1,737
Capitalized Interest 292 637 957 2,660 46,055 6,511
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned subsidiaries 11,850 24,319 3,306 - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges $ 311,986 $ 684,284 $ 717,397 $ 733,625 $ 867,221 $ 808,709
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 2.75 2.92 4.12 3.51 3.22 3.54
- ----------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing PG&E's ratios of earnings to fixed charges,
"earnings" represent net income adjusted for the minority interest in losses of
less than 100% owned affiliates, PG&E's equity in undistributed income or
loss of less than 50% owned affiliates, income taxes and fixed charges (excluding
capitalized interest). "Fixed charges" include interest on long-term debt and short-
term borrowings (including a representative portion of rental expense), amortization
of bond premium, discount and expense, interest on capital leases, and earnings
required to cover the preferred stock dividend requirements of majority owned
subsidiaries.
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Six Months Year ended December 31,
ended ----------------------------------------------------------
(dollars in thousands) 06/30/97 1996 1995 1994 1993 1992
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 302,467 $ 755,209 $1,338,885 $1,007,450 $1,065,495 $1,170,581
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates - 2,488 3,820 (2,764) 6,895 (3,349)
Income tax expense 245,107 554,994 895,289 836,767 901,890 895,126
Net fixed charges 311,694 683,393 715,975 730,965 821,166 802,198
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $ 859,268 $1,996,084 $2,953,969 $2,572,418 $2,795,446 $2,864,556
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 246,038 $ 580,510 $ 627,375 $ 651,912 $ 731,610 $ 739,279
Interest on short-
term debt 52,841 75,310 83,024 77,295 87,819 61,182
Interest on capital
leases 965 3,508 2,735 1,758 1,737 1,737
Capitalized Interest 292 637 957 2,660 46,055 6,511
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned subsidiaries 11,850 24,319 3,306 - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges $ 311,986 $ 684,284 $ 717,397 733,625 867,221 808,709
---------- ---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 5,029 10,057 11,343 4,672 4,814 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 19,552 39,108 99,984 96,039 108,937 130,147
---------- ---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 24,581 49,165 111,327 100,711 113,751 135,283
----------- ---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 336,567 $ 733,449 $ 828,724 $ 834,336 $ 980,972 $ 943,992
=========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.55 2.72 3.56 3.08 2.85 3.03
- ----------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing PG&E's ratios of earnings to combined fixed
charges and preferred stock dividends, "earnings" represent net income adjusted
for the minority interest in losses of less than 100% owned affiliates,
PG&E's equity in undistributed income or loss of less than 50% owned affiliates,
income taxes and fixed charges (excluding capitalized interest). "Fixed charges"
include interest on long-term debt and short-term borrowings (including a representative
portion of rental expense), amortization of bond premium, discount and expense,
interest on capital leases, and earnings required to cover the preferred stock
dividend requirements of majority owned subsidiaries. "Preferred stock dividends"
represent pretax earnings which would be required to cover such dividend requirements.
</TABLE>
<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from
PG&E Corporation and is qualified in its entirety to such financial
statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 19,078,488
<OTHER-PROPERTY-AND-INVEST> 773,115
<TOTAL-CURRENT-ASSETS> 2,939,176
<TOTAL-DEFERRED-CHARGES> 2,637,602
<OTHER-ASSETS> 1,246,557
<TOTAL-ASSETS> 26,674,938
<COMMON> 5,726,608
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2,522,162
<TOTAL-COMMON-STOCKHOLDERS-EQ> 8,248,770
437,500
390,591
<LONG-TERM-DEBT-NET> 7,661,892
<SHORT-TERM-NOTES> 126,167
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 1,402,835
<LONG-TERM-DEBT-CURRENT-PORT> 26,716
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 8,380,467
<TOT-CAPITALIZATION-AND-LIAB> 26,674,938
<GROSS-OPERATING-REVENUE> 6,448,400
<INCOME-TAX-EXPENSE> 239,957
<OTHER-OPERATING-EXPENSES> 5,613,803
<TOTAL-OPERATING-EXPENSES> 5,613,803
<OPERATING-INCOME-LOSS> 834,597
<OTHER-INCOME-NET> 109,520
<INCOME-BEFORE-INTEREST-EXPEN> 944,117
<TOTAL-INTEREST-EXPENSE> 322,195
<NET-INCOME> 381,965
16,556
<EARNINGS-AVAILABLE-FOR-COMM> 365,409
<COMMON-STOCK-DIVIDENDS> 241,754
<TOTAL-INTEREST-ON-BONDS> 204,625
<CASH-FLOW-OPERATIONS> 1,137,779
<EPS-PRIMARY> .91
<EPS-DILUTED> .91
<PAGE>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from
Pacific Gas and Electric Company and is qualified in its entirety by
reference to such financial statements.
</LEGEND>
<SUBSIDIARY>
<NUMBER> 1
<NAME> PACIFIC GAS AND ELECTRIC COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 17,647,274
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 2,304,740
<TOTAL-DEFERRED-CHARGES> 2,537,944
<OTHER-ASSETS> 1,041,462
<TOTAL-ASSETS> 23,531,420
<COMMON> 2,017,521
<CAPITAL-SURPLUS-PAID-IN> 2,563,694
<RETAINED-EARNINGS> 2,519,956
<TOTAL-COMMON-STOCKHOLDERS-EQ> 7,101,171
437,500
402,056
<LONG-TERM-DEBT-NET> 6,984,006
<SHORT-TERM-NOTES> 126,167
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 1,051,897
<LONG-TERM-DEBT-CURRENT-PORT> 23,645
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 7,404,978
<TOT-CAPITALIZATION-AND-LIAB> 23,531,420
<GROSS-OPERATING-REVENUE> 4,552,742
<INCOME-TAX-EXPENSE> 245,107
<OTHER-OPERATING-EXPENSES> 3,737,231
<TOTAL-OPERATING-EXPENSES> 3,737,231
<OPERATING-INCOME-LOSS> 815,511
<OTHER-INCOME-NET> 22,896
<INCOME-BEFORE-INTEREST-EXPEN> 838,407
<TOTAL-INTEREST-EXPENSE> 290,833
<NET-INCOME> 302,467
16,556
<EARNINGS-AVAILABLE-FOR-COMM> 285,911
<COMMON-STOCK-DIVIDENDS> 393,445
<TOTAL-INTEREST-ON-BONDS> 204,625
<CASH-FLOW-OPERATIONS> 928,022
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
