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 September 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
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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 November 5, 1997:
PG&E Corporation 420,843,197 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 SEPTEMBER 30, 1997
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME........................1
CONDENSED BALANCE SHEET.................................2
STATEMENT OF CASH FLOWS ................................3
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME........................4
CONDENSED 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.......................17
COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........18
ELECTRIC INDUSTRY RESTRUCTURING...........................18
Transition Cost Recovery...............................19
Competitive Market Framework...........................22
Accounting for the Effects of Regulation...............23
GAS INDUSTRY RESTRUCTURING................................24
ACQUISITIONS AND SALES....................................25
YEAR 2000 COMPLIANCE......................................26
RESULTS OF OPERATIONS.....................................27
Common Stock Dividend..................................28
Earnings Per Common Share..............................28
Utility................................................28
Other Lines of Business................................29
LIQUIDITY AND CAPITAL RESOURCES
Sources of Capital.....................................29
Cost of Capital Application............................30
1999 General Rate Case.................................30
Environmental Matters..................................31
Legal Matters..........................................31
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.........................................32
ITEM 5. OTHER INFORMATION.........................................38
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................38
SIGNATURE..........................................................40
<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 September 30, Nine months ended September 30,
1997 1996 1997 1996
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Operating Revenues
Electric and gas utility $ 2,541,077 $ 2,439,789 $ 7,093,819 $ 6,664,249
Energy trading 1,120,487 - 2,783,611 -
Other 401,353 82,063 633,887 245,037
----------- ----------- ----------- -----------
Total operating revenues 4,062,917 2,521,852 10,511,317 6,909,286
Operating Expenses
Cost of electric energy 917,849 749,023 2,086,863 1,746,809
Cost of gas 1,272,809 62,186 3,239,849 317,474
Maintenance and other operating 488,838 604,788 1,508,561 1,586,320
Depreciation and decommissioning 472,578 309,715 1,397,381 916,044
Administrative and general 208,199 201,634 578,481 727,775
Property and other taxes 74,364 69,660 237,305 228,249
----------- ----------- ----------- -----------
Total operating expenses 3,434,637 1,997,006 9,048,440 5,522,671
----------- ----------- ----------- -----------
Operating Income 628,280 524,846 1,462,877 1,386,615
Interest income 19,199 16,425 44,613 62,116
Interest expense (174,368) (155,415) (496,823) (482,433)
Other income 9,424 4,728 93,790 16,067
Preferred dividend requirement and
redemption premium (8,278) (8,279) (24,835) (24,835)
----------- ----------- ----------- -----------
Pretax Income 474,257 382,305 1,079,622 957,530
Income Taxes 217,612 156,889 457,569 376,186
----------- ----------- ----------- -----------
Earnings Available for Common Stock $ 256,645 $ 225,416 $ 622,053 $ 581,344
=========== =========== =========== ===========
Weighted Average Common Shares
Outstanding 414,358 411,759 406,875 413,738
Earnings Per Common Share $ .62 $ .55 $ 1.53 $ 1.41
Dividends Declared Per Common Share $ .30 $ .49 $ .90 $ 1.47
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
CONDENSED BALANCE SHEET (in thousands)
<CAPTION>
Balance at September 30, December 31,
1997 1996
------------- -------------
<S> <C> <C>
ASSETS
Plant in Service
Electric $ 25,424,757 $ 24,757,479
Gas 6,766,747 6,558,413
Gas transmission 3,293,715 1,579,693
------------- -------------
Total plant in service (at original cost) 35,485,219 32,895,585
Accumulated depreciation and decommissioning (15,615,168) (14,301,934)
------------- -------------
Net plant in service 19,870,051 18,593,651
Construction Work in Progress 483,171 414,229
Other Noncurrent Assets
Nuclear decommissioning funds 982,275 882,929
Investment in nonregulated projects 730,821 817,259
Other assets 771,608 134,271
------------- -------------
Total other noncurrent assets 2,484,704 1,834,459
Current Assets
Cash and cash equivalents 566,682 143,402
Accounts receivable
Customers, net 1,512,788 1,151,844
Regulatory balancing accounts 581,652 444,156
Energy marketing 531,776 387,342
Inventories and prepayments 693,005 584,201
------------- -------------
Total current assets 3,885,903 2,710,945
Deferred Charges
Income tax-related deferred charges 1,003,350 1,133,043
Other deferred charges 1,687,568 1,550,789
------------- -------------
Total deferred charges 2,690,918 2,683,832
------------- -------------
TOTAL ASSETS $ 29,414,747 $ 26,237,116
============= =============
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock equity $ 9,021,261 $ 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 8,181,912 7,770,067
------------- -------------
Total capitalization 18,031,264 16,972,924
Current Liabilities
Short-term borrowings 1,332,779 680,900
Current portion of long-term debt 643,592 209,867
Accounts payable
Trade creditors 694,934 489,527
Energy marketing 503,309 388,369
Other 557,841 548,157
Accrued taxes 599,939 310,271
Other 840,180 652,671
------------- -------------
Total current liabilities 5,172,574 3,279,762
Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes 3,896,010 3,941,435
Deferred tax credits 350,387 379,563
Other 1,964,512 1,663,432
------------- -------------
Total deferred credits and other noncurrent liabilities 6,210,909 5,984,430
Commitments and Contingencies (Notes 2, 3, and 5)
------------- -------------
TOTAL CAPITALIZATION AND LIABILITIES $ 29,414,747 $ 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 nine months ended September 30, 1997 1996
----------- -----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 622,053 $ 581,344
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and decommissioning 1,397,381 916,044
Amortization 91,977 68,972
Deferred income taxes and tax credits-net (196,295) (160,766)
Other deferred charges (134,575) 58,917
Other noncurrent liabilities (78,981) 190,912
Noncurrent balancing account liabilities and
other deferred credits 342,965 (115,286)
Gain on sale of International Generating Company, Ltd. (120,000) -
Net effect of changes in operating assets
and liabilities:
Accounts receivable (52,221) 55,863
Regulatory balancing accounts receivable 2,278 277,449
Inventories (46,205) 22,408
Accounts payable (94,719) 48,679
Accrued taxes 320,520 164,417
Other working capital (73,444) (39,562)
Other-net 179,113 79,684
----------- -----------
Net cash provided by operating activities 2,159,847 2,149,075
----------- -----------
Cash Flows From Investing Activities
Capital expenditures (1,181,153) (833,974)
Investments in nonregulated projects (165,140) (141,364)
Acquisition of Teco Pipeline Company (40,668) -
Other-net 153,379 (54,613)
----------- -----------
Net cash used by investing activities (1,233,582) (1,029,951)
----------- -----------
Cash Flows From Financing Activities
Common stock issued 39,981 168,596
Common stock repurchased (704,587) (242,414)
Long-term debt issued 363,147 1,074,035
Long-term debt matured, redeemed, or repurchased-net (435,985) (1,214,108)
Short-term debt issued (redeemed)-net 642,878 (829,947)
Dividends paid (388,515) (634,499)
Other-net (19,904) (13,602)
----------- -----------
Net cash used by financing activities (502,985) (1,691,939)
----------- -----------
Net Change in Cash and Cash Equivalents 423,280 (572,815)
Cash and Cash Equivalents at January 1 143,402 734,295
----------- -----------
Cash and Cash Equivalents at September 30 $ 566,682 $ 161,480
=========== ===========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 372,479 $ 359,696
Income taxes 351,666 419,503
<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 September 30, Nine months ended September 30,
1997 1996 1997 1996
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Operating Revenues
Electric $ 2,161,460 $ 2,039,207 $ 5,759,854 $ 5,348,676
Gas 379,617 400,582 1,333,965 1,315,573
Other - 82,063 - 245,037
----------- ----------- ----------- -----------
Total operating revenues 2,541,077 2,521,852 7,093,819 6,909,286
Operating Expenses
Cost of electric energy 730,030 749,023 1,837,206 1,746,809
Cost of gas 48,798 62,186 324,934 317,474
Maintenance and other operating 457,451 604,788 1,463,300 1,586,320
Depreciation and decommissioning 441,439 309,715 1,331,918 916,044
Administrative and general 168,461 201,634 469,573 727,775
Property and other taxes 69,195 69,660 225,674 228,249
----------- ----------- ----------- -----------
Total operating expenses 1,915,374 1,997,006 5,652,605 5,522,671
----------- ----------- ----------- -----------
Operating Income 625,703 524,846 1,441,214 1,386,615
Interest income 15,023 16,425 36,540 62,116
Interest expense (146,301) (155,415) (437,134) (482,433)
Other income 2,326 4,728 3,705 16,067
----------- ----------- ----------- -----------
Pretax Income 496,751 390,584 1,044,325 982,365
Income Taxes 219,665 156,889 464,772 376,186
----------- ----------- ----------- -----------
Net Income 277,086 233,695 579,553 606,179
Preferred dividend requirement and
redemption premium (8,278) (8,279) (24,835) (24,835)
----------- ----------- ----------- -----------
Earnings Available for Common Stock $ 268,808 $ 225,416 $ 554,718 $ 581,344
=========== =========== =========== ===========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEET (in thousands)
<CAPTION>
Balance at September 30, December 31,
1997 1996
------------- -------------
<S> <C> <C>
ASSETS
Plant in Service
Electric $ 25,402,062 $ 24,757,479
Gas 6,753,127 8,138,106
------------- -------------
Total plant in service (at original cost) 32,155,189 32,895,585
Accumulated depreciation and decommissioning (15,137,853) (14,301,934)
------------- -------------
Net plant in service 17,017,336 18,593,651
Construction Work in Progress 466,736 414,229
Other Noncurrent Assets
Nuclear decommissioning funds 982,275 882,929
Investment in nonregulated projects - 817,259
Other assets 99,507 134,271
------------- -------------
Total other noncurrent assets 1,081,782 1,834,459
Current Assets
Cash and cash equivalents 452,038 143,402
Accounts Receivable
Customers, net 1,244,437 1,151,844
Regulatory balancing accounts 581,652 444,156
Energy marketing - 387,342
Inventories and prepayments 550,747 584,201
------------- -------------
Total current assets 2,828,874 2,710,945
Deferred Charges
Income tax-related deferred charges 977,763 1,133,043
Other deferred charges 1,522,779 1,550,789
------------- -------------
Total deferred charges 2,500,542 2,683,832
------------- -------------
TOTAL ASSETS $ 23,895,270 $ 26,237,116
============= =============
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock equity $ 7,171,386 $ 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 6,877,238 7,770,067
------------- -------------
Total capitalization 14,888,180 16,972,924
Current Liabilities
Short-term borrowings 812,850 680,900
Current portion of long-term debt 427,030 209,867
Accounts payable
Trade creditors 421,731 489,527
Associated Companies 212,308 -
Energy marketing - 388,369
Other 546,329 548,157
Accrued taxes 628,069 310,271
Other 649,175 652,671
------------- -------------
Total current liabilities 3,697,492 3,279,762
Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes 3,204,341 3,941,435
Deferred tax credits 350,060 379,563
Other 1,755,197 1,663,432
------------- -------------
Total deferred credits and other noncurrent liabilities 5,309,598 5,984,430
Commitments and Contingencies (Notes 2, 3, and 5)
------------- -------------
TOTAL CAPITALIZATION AND LIABILITIES $ 23,895,270 $ 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 nine months ended September 30, 1997 1996
----------- -----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 579,553 $ 606,179
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and decommissioning 1,331,918 916,044
Amortization 91,999 68,972
Deferred income taxes and tax credits-net (220,464) (160,766)
Other deferred charges (110,347) 58,917
Other noncurrent liabilities (56,245) 190,912
Noncurrent balancing account liabilities and
other deferred credits 298,397 (115,286)
Net effect of changes in operating assets
and liabilities:
Accounts receivable (163,376) 55,863
Regulatory balancing accounts receivable 2,278 277,449
Inventories (17,676) 22,408
Accounts payable (116,155) 48,679
Accrued taxes 336,351 164,417
Other working capital (59,881) (39,562)
Other-net 22,928 54,849
----------- -----------
Net cash provided by operating activities 1,919,280 2,149,075
----------- -----------
Cash Flows From Investing Activities
Capital expenditures (1,116,262) (833,974)
Investments in nonregulated projects - (141,364)
Other-net (89,352) (54,613)
----------- -----------
Net cash used by investing activities (1,205,614) (1,029,951)
----------- -----------
Cash Flows From Financing Activities
Long-term debt issued 354,923 1,074,035
Long-term debt matured, redeemed, or repurchased-net (333,582) (1,214,108)
Short-term debt issued (redeemed)-net 131,950 (829,947)
Dividends paid (548,026) (634,499)
Other-net (10,295) (87,420)
----------- -----------
Net cash used by financing activities (405,030) (1,691,939)
----------- -----------
Net Change in Cash and Cash Equivalents 308,636 (572,815)
Cash and Cash Equivalents at January 1 143,402 734,295
----------- -----------
Cash and Cash Equivalents at September 30 $ 452,038 $ 161,480
=========== ===========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 328,576 $ 359,696
Income taxes 405,698 419,503
<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 U.S. Generating Company (USGen), 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.
Acquisitions and Sales:
- ----------------------
In December 1996, the Corporation acquired Energy Source, a wholesale
commodity marketing subsidiary (renamed PG&E Energy Trading Corporation),
for approximately $23 million. PG&E Energy Trading Corporation has averaged
$269 million in energy trading revenues associated with Energy Source's
operations 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 for
approximately $380 million, consisting of $319 million of PG&E Corporation
common stock and the purchase of a $61 million note.
In April 1997, Bechtel Enterprises, Inc. (Bechtel) acquired Enterprises'
interest in International Generating Company, Ltd., a joint venture between
<PAGE>
Enterprises and Bechtel. The sale resulted in an after-tax gain of
approximately $120 million.
On July 31, 1997, the Corporation completed its acquisition of Valero
Energy Corporation's (Valero) natural gas and natural gas liquids business.
The outstanding shares of Valero common stock were converted into PG&E
Corporation common stock for a total issuance of approximately 31 million
shares equating to a purchase price of $752 million. Approximately $780
million in long-term debt was assumed. Valero's energy trading operations
were combined with PG&E Energy Trading Corporation's operations, and its
pipeline operations were combined into the PG&E Gas Transmission line of
business. Valero energy trading operations have averaged $157 million in
revenues and expenses each month since August 1997. Valero pipeline
operations have averaged $173 million in revenues and expenses each month
since August 1997.
All of the above acquisitions were accounted for using the purchase
method of accounting.
In September 1997, the Corporation became the sole owner of two
partnerships previously jointly owned by the Corporation and Bechtel. The
partnerships, USGen, an independent power developer, and U.S. Operating
Services Company, USGen's operations and maintenance affiliate, were
acquired through the redemption by such partnerships of Bechtel's interests
therein. Subject to regulatory approval, the Corporation will become the
sole owner of a power marketer, USGen Power Services, LP (USGenPS), another
partnership jointly owned by the Corporation and Bechtel, through USGenPS'
redemption of Bechtel's interest therein. In addition, the Corporation
purchased all or part of Bechtel's interest in certain independent power
projects that are affiliated with USGen. Additional project interests will
be acquired following regulatory approvals.
In September 1997, the California Public Utilities Commission (CPUC)
approved PG&E's proposed auction process for the sale of three of its
California fossil-fueled power plants (Morro Bay Power Plant, Moss Landing
Power Plant, and Oakland Power Plant). These three plants have a combined
capacity of 2,645 megawatts (MW) and an estimated book value of
approximately $380 million. The auction process for these plants began in
September 1997. During the initial stage of the auction, non-binding
indications of interest from potential bidders were submitted. A selected
group of these bidders were then invited to submit binding offers by
November 14, 1997. It is anticipated that PG&E will enter into a sales
agreement with the final bidder by the end of 1997. Additionally, the
sales are subject to CPUC approval.
As previously announced, PG&E intends to file its plan with the CPUC late
this year for the sale of four more of its California fossil-fueled power
plants (Potrero Power Plant, Contra Costa Power Plant, Pittsburg Power
Plant, and Hunters Point Power Plant) and its geothermal facility located in
Lake and Sonoma Counties. PG&E will seek to sign sales agreements with
buyers by the end of 1998. These five plants have a combined generating
capacity of 4,718 MW and an estimated book value of approximately $760
million.
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.
Together, the eight power plants represent 98 percent of PG&E's fossil-
fueled and geothermal generating capacity. They generate approximately 22
percent of PG&E's total electric sales volume.
In August 1997, the Corporation announced that USGen (through a special
purpose entity wholly owned by PG&E Corporation) had agreed to acquire a
<PAGE>
portfolio of non-nuclear electric generating assets and power supply
contracts from the New England Electric System (NEES) for approximately
$1.59 billion, plus $85 million to cover NEES employees' early retirement
and severance costs. Including fuel and 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 facilities. The assets are 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 is expected to be completed in 1998 and is
subject to the approval of the Federal Energy Regulatory Commission and
state regulators, among other conditions.
Accounting for 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
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies.
The Corporation's net open position and gains and losses associated with
price risk management activities during year-to-date 1997 were immaterial.
NOTE 2: ELECTRIC INDUSTRY RESTRUCTURING
In 1995, the 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." Transition cost
recovery and the related financial impacts are discussed in the Transition
Cost Recovery and Accounting for the Effects of Regulations sections of this
note.
In 1996, the California legislature passed Assembly Bill 1890
(restructuring legislation) which adopts the basic tenets of the CPUC's
restructuring decision, including recovery of transition costs. The
restructuring legislation freezes, at 1996 levels, all electric customer
rates. In addition, electric rates for residential and small commercial
customers will be reduced by 10 percent on January 1, 1998, and will
continue to be frozen at the reduced level. The rate freeze will continue
until the earlier of March 31, 2002, or until PG&E has recovered its
authorized transition costs (the transition period). The restructuring
legislation also provides for the accelerated recovery of transition costs
associated with owned electric generation facilities and establishes the
operating framework for a competitive electric generation market.
To achieve the 10 percent electric rate reduction for residential and
small commercial customers, the restructuring legislation authorizes the
utilities to finance a portion of their transition costs through the
issuance of "rate reduction bonds." The rate reduction bonds would be
issued by a trust established by the California Infrastructure and Economic
Development Bank (Bank). The term of the bonds will 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. The combination
of the longer term and the reduced interest cost is expected to lower the
<PAGE>
amount paid by residential and small commercial customers each year during
the transition period, thereby achieving the 10 percent reduction in rates.
PG&E intends that the rate reduction bonds will be issued before the end of
1997.
In September 1997, the CPUC approved PG&E's application to issue the
bonds. A consumer group's petition for rehearing of the decision was denied
by the CPUC on October 22, 1997, although the consumer group has indicated
it plans to take further legal action. Further, on November 10, 1997, the
Bank approved the terms and conditions of the bonds. However, before
issuance, the registration statement filed with the Securities and Exchange
Commission (SEC), with respect to the bonds, must be declared effective by
the SEC.
PG&E currently expects that approximately $3.0 billion of rate reduction
bonds will be issued. The actual amount issued will depend on a variety of
factors, including the market interest rate on the bonds, the credit rating
of the bonds, and whether the bond issuance is delayed beyond January 1,
1998. Finally, the CPUC has authorized PG&E to file a revised application
for approval of an alternative method of recovering the reduced revenues
resulting from the 10 percent rate reduction, if for any reason, the bonds
are not issued.
Transition Cost Recovery:
- ------------------------
The restructuring legislation authorizes the CPUC to determine the costs
eligible for recovery as transition costs. 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 or
prior periods and allowed to be included in rates in subsequent periods.)
The amount of transition costs will be based on, among other things, the
aggregate of above-market and below-market values of utility-owned
generation assets and obligations. PG&E cannot determine the exact amount
of above-market sunk costs that will be recoverable as transition costs
until a market valuation process (appraisal or sale) is completed for each
generation facility. This process will be completed by December 31, 2001.
At September 30, 1997, PG&E's net investment in Diablo Canyon Nuclear Power
Plant (Diablo Canyon) and non-nuclear generation facilities was $3.9 billion
and $2.7 billion, respectively. The above-market portion of these assets is
eligible for recovery as transition costs. 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 kilowatt-hour
(kWh) beginning in 1997 and escalating at 3.2 percent per year. In
addition, as of September 30, 1997, PG&E has accumulated approximately $1.8
billion of generation-related net regulatory assets and obligations which
are eligible for collection from distribution customers through a
competition transition charge (CTC) and which are probable of recovery.
Under the restructuring legislation, most transition costs must be
recovered by March 31, 2002, under an accelerated recovery mechanism.
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
<PAGE>
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.
In compliance with the CPUC's restructuring decision and the
restructuring legislation, PG&E has filed numerous regulatory applications
and proposals that detail its plan to recover transition costs. PG&E's
transition cost 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) recovery of most
transition costs during the transition period. Under PG&E's transition cost
recovery plan, PG&E would receive a reduced return on common equity for
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.
In conjunction with PG&E's transition cost recovery plan as relating to
Diablo Canyon, the CPUC authorized PG&E to: (1) recover certain ongoing
costs and capital additions through an established Incremental Cost
Incentive Price (ICIP) per kWh generated by the facility, and (2) accelerate
recovery of PG&E's investment in Diablo Canyon from a twenty-year period
ending in 2016 to a five-year period ending in 2001. During the accelerated
recovery period, Diablo Canyon is expected to earn a reduced rate of return
on common equity equal to 90 percent of PG&E's embedded cost of long-term
debt. PG&E's authorized cost of long-term debt is 7.52 percent in 1997.
The CPUC has not clarified 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 may be significantly reduced during the
transition period, which would reduce recovery of ICIP-related costs. In
1997, the CPUC authorized $515 million in ICIP revenues based upon the
established ICIP and an 83.6 percent capacity factor. In addition, 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.
In consideration of the CPUC's authorization of Diablo Canyon's
recovery, 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 transition
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 nine months of the year by $436 million, for an
after-tax reduction to earnings per share of $.64.
In September 1997, the CPUC adopted a decision addressing transition cost
recovery for capital additions to PG&E's non-nuclear generating facilities.
The decision allows PG&E to recover costs of capital additions made in 1996
and 1997 based upon an after-the-fact reasonableness review. All capital
additions found reasonable by the CPUC through this process will be
recoverable as transition costs. PG&E does not believe that the CPUC's
decision will materially impact PG&E's ability to recover in rates capital
additions made during 1996 and 1997.
PG&E's ability to recover its transition costs during the transition
period will be dependent on several factors. These factors include: (1) the
continued application of the regulatory framework established by the
restructuring legislation, (2) the amount of transition costs approved by
the CPUC, (3) the market value of PG&E's generation plants, (4) future sales
<PAGE>
levels, (5) future fuel and operating costs, (6) the extent to which
authorized revenues to recover distribution costs are increased or
decreased, (7) the market price of electricity, and (8) the successful
financing of the 10 percent rate reduction mandated by the restructuring
legislation. Given its current evaluation of these factors, PG&E believes
it will recover its transition costs and 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.
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 deferred in balancing
accounts. Any residual balance in these accounts will be available to use
for recovery of transition costs. The residual balance in these accounts
at September 30, 1997, was $12 million. Amounts recorded in balancing
accounts will be subject to a reasonableness review by the CPUC.
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 PG&E to write off regulatory assets when
they are no longer probable of recovery. SFAS No. 121 also requires PG&E to
record impairment losses for long-lived assets when related future cash
flows are less than the carrying value of the assets.
In August 1997, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board (FASB) reached a consensus on 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) which provided authoritative guidance on the applicability of
SFAS No. 71 during PG&E's transition period. The EITF requires 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 did 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. PG&E has accumulated approximately $1.8 billion of generation-
related regulatory assets which are eligible for collection from
distribution customers through a CTC and which are probable of recovery.
Substantially all regulatory assets are reflected on PG&E's and PG&E
Corporation's balance sheets in deferred charges and regulatory balancing
accounts. In addition, above-market generation-related sunk costs, which
will be determined as part of the market valuation process discussed above,
also will be eligible for collection through the CTC imposed on
distribution customers. At September 30, 1997, PG&E's net investment in
generation facilities, including Diablo Canyon, was $6.6 billion and was
included in electric plant in service on PG&E's and PG&E Corporation's
balance sheets.
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
<PAGE>
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 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.
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 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.
NOTE 3: NATURAL GAS MATTERS
In August 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 increase the opportunity for residential
customers to choose the gas supplier of their choice, establish gas
transmission rates for the period from the implementation of the Accord
(expected to be March 1, 1998) through December 2002, establish an
incentive mechanism to measure the reasonableness of PG&E's gas purchases
for residential and small commercial customers, and offer more
transportation services and choices to natural gas customers. The Accord
also will resolve numerous major regulatory gas proceedings in which PG&E
and many other parties are involved.
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. The decision also adopts a
discounting rule. Under this discounting rule, whenever PG&E offers a
shipper a discount on its Line 400/401 (its pipelines which access Canadian
suppliers), PG&E is required to contemporaneously offer a commensurate
discount to all shippers for similiar services on its Line 300 (its pipeline
which accesses Southwestern suppliers) and its California Gas Production
Path. 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
small 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 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 September 30, 1997, approximately $498 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 percent cumulative quarterly income
preferred securities (QUIPS), with an aggregate liquidation value of $300
million. Concurrent with the issuance of the QUIPS, the Trust issued to
PG&E 371,135 shares of common securities with an aggregate liquidation value
of approximately $9 million. The only assets of the Trust are deferrable
interest subordinated debentures issued by PG&E with a face value of
<PAGE>
approximately $309 million, an interest rate of 7.90 percent, 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 September 30, 1997, of $220 million for hazardous
waste remediation costs at those sites, including fossil-fueled power
plants. Environmental remediation at identified sites may be as much as
$475 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
<PAGE>
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 September 30, 1997, of $170 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 September 30, 1997, PG&E's net investment was $693 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 performance-based ratemaking 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. On September 8, 1997,
the Court of Appeal denied the plaintiff cities' appeal of these rulings.
As no further appeal was taken, the January and March 1996 rulings have
become final. The Court has set a status conference for December 1997 with
regard to the remaining claims.
PG&E's annual systemwide city electric franchise fees for the remaining
class member cities not subject to the January and March 1996 final 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 September 30, 1997).
<PAGE>
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 and, in some cases, property damage, 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.
Texas Franchise Fee Litigation:
In connection with PG&E Corporation's acquisition of Valero, now known as
PG&E Gas Transmission, Texas Corporation (GTT), GTT succeeded to the
litigation described below.
Valero and Southern Union Company (Southern Union) are defendants in a
lawsuit brought by the City of Edinburg, Texas (City) in 1995, regarding
certain ordinances of the City that granted franchises to Rio Grande Valley
Gas Company (RGV) (a division of Southern Union) and its predecessors,
allowing RGV to sell and distribute natural gas within the City. RGV was
formerly owned by Valero. The City alleges that the defendants used RGV's
facilities to sell or transport natural gas in Edinburg in violation of the
ordinances and franchises granted by the City, and that RGV has not fully
paid all franchise fees due the City. The City also alleges that the
defendants used the public property of the City without compensating the
City for such use and contends that Valero must agree to a franchise or face
removal by injunction. The lawsuit seeks actual damages stated to be in
excess of $15 million, unspecified punitive monetary damages, and injunctive
relief against Valero and Southern Union. The City of Edinburg lawsuit is
scheduled for trial on June 15, 1998.
In April 1997, the City of Mercedes (Mercedes) filed a lawsuit which is
currently pending against Reata Industrial Gas Company (now known as Valero
Gas Marketing Company) and Reata Industrial Gas, L.P. (now known as PG&E
Reata Energy, L.P., a subsidiary of GTT) (defendants). On September 4,
1997, Mercedes amended its petition to include class action claims and
requested to be named as class representative for a statewide class
consisting of all Texas municipal corporations, municipalities, towns, and
villages (excluding certain cities which filed separate actions), in which
any of the defendants have sold or supplied gas, or used public rights-of-
way to transport gas.
Mercedes asserts that the defendants, both of which do not own any
pipelines, have operated as "ghost pipelines" that have "used" public
property without consent or franchise from the cities in which the
defendants have sold gas. Mercedes has requested a damage award, but has
not specified an amount.
<PAGE>
Valero, PG&E Gas Transmission Teco, Inc. and its subsidiaries, and PG&E
Energy Trading Corporation, are also now defendants in a class action
lawsuit brought by the Texas cities of San Benito, Primera, and Port Isabel.
These cities serve as class representatives for a class consisting of every
incorporated municipality in Texas (excluding certain cities which filed
separate actions) where any of the defendants engaged in business activities
related to natural gas or natural gas liquids. Plaintiffs allege, among
other things, that (1) the defendants that own or operate pipelines (as
merchants or transporters) have occupied city property and conducted
pipeline operations without the cities' consent and without compensating the
cities for use of the cities' properties, and (2) the defendants that are
gas marketers have failed to pay the cities for using pipelines located in
the cities to flow gas under city streets to gas customers. Plaintiffs also
allege various tort and statutory claims against defendants for failure to
secure the cities' consent. Damages are not quantified.
In addition to the litigation involving the City of Edinburg, the City of
Mercedes, and the cities of San Benito, Primera, and Port Isabel, there are
four lawsuits involving claims of a similar nature. Damages are not
quantified in any of these additional cases.
The Corporation believes that the ultimate outcome of this matter will
not have a material adverse impact on its financial position.
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 PG&E Corporation and the following five business lines (collectively, the
Corporation):
- - Utility (consisting of PG&E)
- - PG&E Gas Transmission
- - PG&E Energy Trading
- - PG&E Energy Services
- - U.S. Generating Company (USGen)
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
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 anticipated financial impacts of gas and electric industry restructuring.
Words such as "estimates," "expects," "anticipates," "plans," "believes," and
similar expressions 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
<PAGE>
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
to all customers.
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 four 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.
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." Transition cost recovery, the competitive
market framework, and the related financial impacts are discussed in the
Transition Cost Recovery, Competitive Market Framework, and Accounting for
the Effects of Regulations sections of the Management's Discussion and
Analysis of Financial Condition and Results of Operations.
In 1996, the California legislature passed Assembly Bill 1890
(restructuring legislation) which adopts the basic tenets of the CPUC's
restructuring decision, including recovery of transition costs. The
restructuring legislation freezes, at 1996 levels, all electric customer
rates. In addition, electric rates for residential and small commercial
<PAGE>
customers will be reduced by 10 percent on January 1, 1998, and will
continue to be frozen at the reduced level. The rate freeze will continue
until the earlier of March 31, 2002, or until PG&E has recovered its
authorized transition costs (the transition period). The restructuring
legislation also provides for the accelerated recovery of transition costs
associated with owned electric generation facilities and establishes the
operating framework for a competitive electric generation market.
To achieve the 10 percent electric rate reduction for residential and
small commercial customers, the restructuring legislation authorizes the
utilities to finance a portion of their transition costs through the
issuance of "rate reduction bonds." The rate reduction bonds would be
issued by a trust established by the California Infrastructure and Economic
Development Bank (Bank). The term of the bonds will 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. The combination
of the longer term and the reduced interest cost is expected to lower the
amount paid by residential and small commercial customers each year during
the transition period, thereby achieving the 10 percent reduction in rates.
PG&E intends that the rate reduction bonds will be issued before the end of
1997.
In September 1997, the CPUC approved PG&E's application to issue the
bonds. A consumer group's petition for rehearing of the decision was denied
by the CPUC on October 22, 1997, although the consumer group has indicated
it plans to take further legal action. Further, on November 10, 1997, the
Bank approved the terms and conditions of the bonds. However, before
issuance, the registration statement filed with the Securities and Exchange
Commission (SEC), with respect to the bonds, must be declared effective by
the SEC.
After the bonds are issued, PG&E will collect a separate nonbypassable
tariff on behalf of the bondholders to recover principal, interest, and
related costs over the life of the bonds from residential and small
commercial customers. In exchange for the bond proceeds, PG&E will transfer
its right to the future revenues from this separate tariff to an affiliated
special purpose entity. The bonds will be secured by the future revenue
from the separate tariff and not by PG&E's assets. The bonds will be
reflected as long-term debt on PG&E's balance sheet. (However, creditors of
PG&E will not have any recourse to revenues from the separate tariff.) PG&E
expects to use the proceeds from the issuance of the rate reduction bonds to
retire utility debt and equity, while maintaining its CPUC-authorized
capital structure, exclusive of the bonds.
PG&E currently expects that approximately $3.0 billion of rate reduction
bonds will be issued. The actual amount issued will depend on a variety of
factors, including the market interest rate on the bonds, the credit rating
of the bonds, and whether the bond issuance is delayed beyond January 1,
1998. Finally, the CPUC has authorized PG&E to file a revised application
for approval of an alternative method of recovering the reduced revenues
resulting from the 10 percent rate reduction, if for any reason, the bonds
are not issued.
Transition Cost Recovery:
- ------------------------
The restructuring legislation authorizes the CPUC to determine the costs
eligible for recovery as transition costs. 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.
<PAGE>
(In general, regulatory assets are expenses deferred in the current or prior
periods and allowed to be included in rates in subsequent periods.)
The amount of transition costs will be based on, among other things, the
aggregate of above-market and below-market values of utility-owned
generation assets and obligations. PG&E cannot determine the exact amount
of above-market sunk costs that will be recoverable as transition costs
until a market valuation process (appraisal or sale) is completed for each
generation facility. This process will be completed by December 31, 2001.
At September 30, 1997, PG&E's net investment in Diablo Canyon and non-
nuclear generation facilities was $3.9 billion and $2.7 billion,
respectively. The above-market portion of these assets is eligible for
recovery as transition costs. 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 kilowatt-hour (kWh) beginning
in 1997 and escalating at 3.2 percent per year. In addition, as of
September 30, 1997, PG&E has accumulated approximately $1.8 billion of
generation-related net regulatory assets and obligations which are eligible
for collection from distribution customers through a competition transition
charge (CTC) and which are probable of recovery.
Under the restructuring legislation, most transition costs must be
recovered by March 31, 2002, under an accelerated recovery mechanism.
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.
In compliance with the CPUC's restructuring decision and the
restructuring legislation, PG&E has filed numerous regulatory applications
and proposals that detail its plan to recover transition costs. PG&E's
transition cost 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 (PPP), and
generation, (2) development of a ratemaking mechanism to track and match
revenues and cost recovery during the transition period, and (3) recovery of
most transition costs during the transition period. Under PG&E's transition
cost recovery plan, PG&E would receive a reduced return on common equity for
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 unbundling of PG&E's revenue requirement would enable it to separate
revenue provided by frozen rates into transmission, distribution, PPP, and
generation. As proposed, revenues collected under frozen rates would be
assigned to transmission, distribution, and PPP based upon their respective
cost of service. Revenue would also be provided for other costs, including
nuclear decommissioning, rate-reduction-bond debt service, the ongoing 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 some exceptions. PG&E does not
believe the decision will have a material impact on its ability to recover
transition costs.
<PAGE>
In conjunction with PG&E's transition cost recovery plan as relating to
Diablo Canyon, the CPUC authorized PG&E to: (1) recover certain ongoing
costs and capital additions through an established Incremental Cost
Incentive Price (ICIP) per kWh generated by the facility, and (2)
accelerate recovery of PG&E's investment in Diablo Canyon from a twenty-
year period ending in 2016 to a five-year period ending in 2001. During
the accelerated recovery period, Diablo Canyon is expected to earn a
reduced rate of return on common equity equal to 90 percent of PG&E's
embedded cost of long-term debt. PG&E's authorized cost of long-term debt
is 7.52 percent in 1997.
The CPUC has not clarified 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 may be significantly reduced during
the transition period, which would reduce recovery of ICIP-related costs.
In 1997, the CPUC authorized $515 million in ICIP revenues based upon the
established ICIP and an 83.6 percent capacity factor. In addition, a
consumer group 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.
In consideration of the CPUC's authorization of Diablo Canyon's
recovery, 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 transition
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 nine months of the year by $436 million, for an
after-tax reduction to earnings per share of $.64.
In September 1997, the CPUC adopted a decision addressing transition cost
recovery for capital additions to PG&E's non-nuclear generating facilities.
The decision allows PG&E to recover costs of capital additions made in 1996
and 1997 (and in 1998 for fossil-fueled plants completely divested by March
31, 1998) based upon an after-the-fact reasonableness review. All capital
additions found reasonable by the CPUC through this process will be
recoverable as transition costs.
Capital additions made in 1998 and thereafter to non-nuclear generation-
related assets and capital additions made to fossil-fueled generating assets
which are not completely divested by March 31, 1998, may be recovered in two
ways. Recovery may be either (1) from the Independent System Operator (ISO)
agreements for certain qualified plants, or (2) from revenues collected from
sales of electricity to the Power Exchange (PX). The cost of capital
additions made to hydroelectric and geothermal facilities in 1998 and
thereafter may be recoverable in rates under an alternative revenue
requirement mechanism now being considered by the CPUC in a separate
proceeding.
Further, the CPUC deferred to future proceedings how the cost of capital
additions completed in 1998 and thereafter will be accounted for in
determining the market value of generation-related assets for purposes of
calculating the uneconomic portion of the generation-related assets
recoverable as transition costs.
PG&E does not believe that the CPUC's decision will materially impact
PG&E's ability to recover in rates capital additions made during 1996 and
1997 and made through the end of the transition period.
PG&E's ability to recover its transition costs during the transition
period will be dependent on several factors. These factors include: (1)
the continued application of the regulatory framework established by the
<PAGE>
restructuring legislation, (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, (6) the extent to which
authorized revenues to recover distribution costs are increased or
decreased, (7) the market price of electricity, and (8) the successful
financing of the 10 percent rate reduction mandated by the restructuring
legislation. Given its current evaluation of these factors, PG&E believes
it will recover its transition costs and 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.
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 deferred in balancing
accounts. Any residual balance in these accounts will be available to use
for recovery of transition costs. The residual balance in these accounts
at September 30, 1997, was $12 million. Amounts recorded in balancing
accounts will be subject to a reasonableness review by the CPUC.
The most significant factors affecting the amount of the 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, and the decline in uncollected electric
balancing accounts.
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 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
used, for transmission and distribution services, for PPP, 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
<PAGE>
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.
The Corporation's subsidiary, PG&E Energy Services Corporation, currently
markets electric and gas commodity and other energy-related services in
California and nationwide. It plans to compete as a direct access provider
in the California retail electric market commencing January 1, 1998, when
that market opens.
On October 31, 1997, a proposed decision (PD) was issued in the CPUC
proceeding to establish rules regarding transactions between electric
utilities and certain of their affiliates. Among other things, alternate
provisions of the PD would (1) preclude, for at least two years, utilities
from having any transaction with an affiliate that offers direct access
services to customers within the utility's service territory, with certain
exceptions, and (2) forbid utilities from allowing affiliates to use the
utility's name and logo. If these alternate provisions of the PD are
adopted by the CPUC, PG&E Energy Services would be precluded from competing
in PG&E's service territory for at least the first two years of direct
access and would also be at a disadvantage in competing in the national
retail electric market.
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 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 PG&E to write off regulatory assets
when they are no longer probable of recovery. SFAS No. 121 also requires
PG&E to record impairment losses for long-lived assets when related future
cash flows are less than the carrying value of the assets.
In August 1997, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board (FASB) reached a consensus on Issue No. 97-4,
"Deregulation of the Pricing of Electricity - Issues Related to the
<PAGE>
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) which provided authoritative guidance on the applicability of
SFAS No. 71 during PG&E's transition period. The EITF requires 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 did 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. PG&E has accumulated approximately $1.8 billion of generation-
related regulatory assets which are eligible for collection from
distribution customers through a CTC and which are probable of recovery.
Substantially all regulatory assets are reflected on PG&E's and PG&E
Corporation's balance sheets in deferred charges and regulatory balancing
accounts. In addition, above-market generation-related sunk costs, which
will be determined as part of the market valuation process discussed above,
also will be eligible for collection through the CTC imposed on
distribution customers. At September 30, 1997, PG&E's net investment in
generation facilities, including Diablo Canyon, was $6.6 billion and was
included in electric plant in service on PG&E's and PG&E Corporation's
balance sheets.
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.
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 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.
GAS INDUSTRY RESTRUCTURING:
In August 1997, the CPUC unanimously adopted a final decision approving the
Gas Accord Settlement (Accord), which was submitted in 1996 for CPUC
approval. 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, establish gas transmission rates for the period
from the implementation of the Accord (expected to be March 1, 1998) through
December 2002, establish an incentive mechanism to measure the
reasonableness of PG&E's gas purchases for residential and small commercial
customers, and offer more transportation services and choices to natural gas
customers. The Accord also will 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/Pacific Gas
Transmission pipeline that extends from the Canadian border to Kern River
<PAGE>
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 shipper a discount on its Line 400/401 (its pipelines
which access Canadian suppliers), PG&E is required to contemporaneously
offer a commensurate discount to all shippers for similar services on its
Line 300 (its pipeline which accesses Southwestern suppliers) and its
California Gas Production Path.
- The decision approves the core procurement incentive mechanisms 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 small
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 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 September 30, 1997, approximately $498 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.
ACQUISITIONS AND SALES:
On July 31, 1997, the Corporation completed its acquisition of Valero
Energy Corporation's (Valero) natural gas and natural gas liquids business.
The outstanding shares of Valero common stock were converted into PG&E
Corporation common stock for a total issuance of approximately 31 million
shares equating to a purchase price of $752 million. Approximately $780
million in long-term debt was assumed. Valero's energy trading operations
were combined with PG&E Energy Trading Corporation's operations, and its
pipeline operations were combined into the PG&E Gas Transmission line of
business. Valero energy trading operations have averaged $157 million in
revenues and expenses each month since August 1997. Valero pipeline
operations have averaged $173 million in revenues and expenses each month
since August 1997. The acquisition was accounted for using the purchase
method of accounting.
In September 1997, the Corporation became the sole owner of two
partnerships previously jointly owned by the Corporation and Bechtel
Enterprises, Inc. (Bechtel). The partnerships, USGen, an independent power
<PAGE>
developer, and U.S. Operating Services Company, USGen's operations and
maintenance affiliate, were acquired through the redemption by such
partnerships of Bechtel's interests therein. Subject to regulatory
approval, the Corporation will become the sole owner of a power marketer,
USGen Power Services, LP (USGenPS), another partnership jointly owned by
the Corporation and Bechtel, through USGenPS' redemption of Bechtel's
interest therein. In addition, the Corporation purchased all or part of
Bechtel's interest in certain independent power projects that are
affiliated with USGen. Additional project interests will be acquired
following regulatory approvals.
In September 1997, the CPUC approved PG&E's proposed auction process for
the sale of three of its California fossil-fueled power plants (Morro Bay
Power Plant, Moss Landing Power Plant, and Oakland Power Plant). These
three plants have a combined capacity of 2,645 megawatts (MW) and an
estimated book value of approximately $380 million. The auction process for
these plants began in September 1997. During the initial stage of the
auction, non-binding indications of interest from potential bidders were
submitted. A selected group of these bidders were then invited to submit
binding offers by November 14, 1997. It is anticipated that PG&E will
enter into a sales agreement with the final bidder by the end of 1997.
Additionally, the sales are subject to CPUC approval.
As previously announced, PG&E intends to file its plan with the CPUC late
this year for the sale of four more of its California fossil-fueled power
plants (Potrero Power Plant, Contra Costa Power Plant, Pittsburg Power
Plant, and Hunters Point Power Plant) and its geothermal facility located in
Lake and Sonoma Counties. PG&E will seek to sign sales agreements with
buyers by the end of 1998. These five plants have a combined generating
capacity of 4,718 MW and an estimated book value of approximately $760
million.
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.
Together, the eight power plants represent 98 percent of PG&E's fossil-
fueled and geothermal generating capacity. They generate approximately 22
percent of PG&E's total electric sales volume.
In August 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 (NEES) for approximately
$1.59 billion, plus $85 million to cover NEES employees' early retirement
and severance costs. Including fuel and 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 facilities. The assets are 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 is expected to be completed in 1998 and is
subject to the approval of the Federal Energy Regulatory Commission (FERC)
and state regulators, among other conditions.
YEAR 2000 COMPLIANCE
In 1995, PG&E began reviewing and assessing its computer and information
systems in anticipation of Year 2000 when its software programs and systems
will be required to recognize dates in the next millennium. PG&E currently
expects to complete all critical software conversion modifications by the
end of 1998. The Corporation does not currently anticipate any adverse
material impact on its or PG&E's financial position or results of
operations as a result of the Year 2000 issue.
<PAGE>
RESULTS OF OPERATIONS:
The Corporation's results of operations were derived primarily from five
business lines: Utility (consisting of PG&E), PG&E Gas Transmission, PG&E
Energy Trading, PG&E Energy Services, and 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 average
percentages of assets, operating revenues, operating expenses, and number of
employees. The results of operations for Utility do not agree to the
Pacific Gas and Electric Company Statement of Consolidated Income due to the
parent company allocations. 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 nine months ended September 30, 1997 and 1996, and total assets at
September 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
September 30, 1997
Operating revenues $ 2,541 $ 1,522 $ 4,063
Operating expenses 1,919 1,516 3,435
--------- -------- --------
Operating income before income taxes 622 6 628
Net income: Earnings available for Common Stock 267 (10) 257
Earnings per common share 0.65 (0.03) 0.62
September 30, 1996
Operating revenues 2,440 82 2,522
Operating expenses 1,941 56 1,997
-------- -------- --------
Operating income before income taxes 499 26 525
Net income: Earnings available for Common Stock 213 12 225
Earnings per common share 0.51 0.04 0.55
For the nine months ended
September 30, 1997
Operating revenues $ 7,094 $ 3,417 $ 10,511
Operating expenses 5,660 3,388 9,048
-------- -------- --------
Operating income before income taxes 1,434 29 1,463
Net income: Earnings available for Common Stock 550 72 622
Earnings per common share 1.35 0.18 1.53
Total assets at September 30 $ 23,895 $ 5,520 $ 29,415
September 30, 1996
Operating revenues 6,664 245 6,909
Operating expenses 5,363 159 5,522
-------- -------- --------
Operating income before income taxes 1,301 86 1,387
Net income: Earnings available for Common Stock 534 47 581
Earnings per common share 1.29 0.12 1.41
Total assets at September 30 $ 23,644 $ 2,082 $ 25,726
</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 nine months ended September 30,
1997, increased as compared to the same periods in 1996. This increase is
primarily due to the activity discussed below.
Utility:
- --------
Utility operating revenues increased for the three and nine months ended
September 30, 1997, as compared with the same periods in 1996. A portion
of the increase for both periods is due to increased revenues associated
with electric transmission and distribution system reliability authorized
by the restructuring legislation. For the nine months ended September 30,
1997, a portion of the 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 second quarter 1997 scheduled outage, while no revenue recovery was
provided during the second quarter 1996 scheduled outage. For the nine
months ended September 30, 1997, there was also an increase in energy cost
revenues to recover energy cost increases in both natural gas prices and
sales volume provided by PG&E's energy cost recovery mechanism. 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 decreased for the three months ended
September 30, 1997, and increased for the nine months ended September 30,
1997, as compared to the same periods in 1996. Decreases for the three
months ended September 30, 1997, compared to the same period in 1996 are
due to a decrease to maintenance and other operating expenses due to
several one-time charges associated with California gas related matters
recorded in the third quarter of 1996. This decrease was partially offset
by an increase in Diablo Canyon depreciation associated with the new Diablo
Canyon ratemaking structure for 1997. Increases for the nine months ended
September 30, 1997, compared to the same period in 1996 also resulted from
the increase to Diablo Canyon depreciation. These increases were partially
offset by the decreases noted above, associated with California Gas related
matters, and a decrease in administrative and general expenses due to a
litigation reserve which was recorded in the second quarter of 1996.
<PAGE>
Other Lines of Business:
- ------------------------
Operating revenues and expenses increased for other lines of business for
the three and nine months ended September 30, 1997, as compared with the
same periods in 1996. This increase is primarily due to the acquisition of
Energy Source in December 1996. Revenues and expenses associated with this
acquisition are approximately $269 million per month. The acquisition of
Valero on July 31, 1997, also contributed to the increase. Revenues and
expenses associated with this acquisition are approximately $330 million
per month.
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 the Corporation's capital requirements, the
Corporation may repurchase equity and long-term debt in order to manage the
overall balance of its capital structure.
In May 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 in the section entitled "Electric
Industry Restructuring." This credit facility augments the existing PG&E $1
billion five-year credit facility. In August 1997, PG&E Corporation entered
into a $500 million temporary credit facility for general corporate
purposes, which raises PG&E Corporation's committed credit lines to a total
of $1 billion. The Corporation's short-term borrowings increased $643
million during the nine-month period ended September 30, 1997.
During the nine months ended September 30, 1997, PG&E Corporation issued
$1,109 million of common stock. Of this common stock, $752 and $319
million were issued to acquire Valero and Teco Pipeline Company,
respectively. The remaining $38 million was issued through the Dividend
Reinvestment Plan and the Stock Option Plan. Also during the nine months
ended September 30, 1997, PG&E Corporation repurchased $705 million of its
common stock on the open market.
In September 1997, PG&E issued $315 million of variable rate pollution
bonds to refund the same amount of fixed-rate pollution control bonds on
December 1, 1997. The Corporation assumed approximately $780 million of
long-term debt in connection with the acquisition of Valero.
Long-term debt matured, redeemed, or repurchased during the nine months
ended September 30, 1997, amounted to $436 million. Of this amount, $58
million related to PG&E's redemption of its 12 percent 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 $166 million related primarily
to the scheduled maturity of long-term debt.
As discussed above in "Electric Industry Restructuring," PG&E intends
that the rate reduction bonds will be issued before the end of 1997, subject
to the SEC declaring effective the registration statement filed with
respect to the bonds. PG&E currently expects that approximately $3.0
billion of rate reduction bonds will be issued. The actual amount issued
will depend on a variety of factors, including the market interest rate on
the bonds, the credit rating of the bonds, and whether the bond issuance is
<PAGE>
delayed beyond January 1, 1998. For a discussion of other factors affecting
the rate reduction bonds, see the section entitled "Electric Industry
Restructuring."
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 11.60 percent authorized 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. Intervening parties are
recommending a 1998 cost of common equity ranging from 9.60 to 11.60
percent. A CPUC decision is expected in December 1997.
1999 General Rate Case (GRC):
- ----------------------------
In September 1997, PG&E filed with the CPUC a notice of intent to file its
Test Year 1999 GRC application later this year. In its notice of intent,
PG&E stated that it would request an increase in authorized base revenues
for electric and gas retail customers, effective January 1, 1999. The
requested increase consists of an increase of $703 million in electric
revenues and an increase of $506 million in gas revenues over authorized
base revenues presently in effect.
PG&E's requested increase in electric base revenues will not increase
customer electric rates because these rates are frozen at the 1996 levels,
as part of the California electric industry restructuring legislation.
Under the frozen electric rates, increases in base revenues will reduce the
amount of revenue available to recover transition costs. To the extent
transition costs are not collected by the end of the rate freeze period,
PG&E will be at risk to recover its remaining transition costs through
market-based revenues.
Since the FERC will authorize the revenue to be collected in rates for
electric transmission services, PG&E's GRC application will not seek
approval of revenues to recover costs of transmission services from the
CPUC.
In August 1997, the CPUC approved the Accord which will establish gas
transmission and storage rates for the period from the implementation of
the Accord (expected to be March 1, 1998) through December 2002. The
requested increase in gas base revenues will not result in an increase in
customer gas transmission and storage rates, since they have already been
established through the Accord.
PG&E expects that the revenue adjustments it will propose in the GRC
will change as a result of other pending CPUC proceedings, including PG&E's
1998 Cost of Capital proceeding which is expected to be decided before year
end 1997. Public hearings on the 1999 GRC will be scheduled after PG&E
files its application later this year.
<PAGE>
Environmental Matters:
- ---------------------
PG&E assesses, on an ongoing basis, compliance with laws and regulations
related to hazardous substance remediation. At September 30, 1997, PG&E
had an accrued liability of $220 million for remediation costs at sites,
including fossil-fueled power plants, where such costs are probable and
quantifiable. The costs at identified sites may be as much as $475 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 September 30, 1997, of $170 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 Part II,
Item 1, Legal Proceedings and 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
Please refer to Part II, Item 1, of PG&E Corporation (Corporation) and
Pacific Gas and Electric Company's (PG&E) Quarterly Report on Form 10-
Q for the quarter ended June 30, 1997, for a discussion of
developments in this matter which was previously reported in the
Corporation and PG&E's Annual Report on Form 10-K for the year ended
December 31, 1996.
B. Counties Franchise Fees Litigation
As previously disclosed in the Corporation's and PG&E's Annual Report
on Form 10-K for the year ended December 31, 1996, on March 31, 1994,
the Counties of Alameda and Santa Clara filed a complaint in Santa
Clara County Superior Court against PG&E on behalf of themselves and
purportedly as a class action on behalf of 47 counties with which PG&E
has gas or electric franchise contracts. Franchise contracts require
PG&E to pay fees on an annual basis to cities and counties for the
right to use or occupy public streets and roads. The complaint
alleges that, since at least 1987, PG&E has intentionally underpaid
its franchise fees to the counties in an unspecified amount.
The complaint cites two reasons for the alleged underpayment of fees.
Based on their interpretation of certain legislation, the plaintiffs
allege that PG&E has been using the wrong methodology to compute the
franchise fees payable to the plaintiff counties. The plaintiffs also
allege that fees have been underpaid due to incorrect calculations
under the methodology actually used by PG&E.
The parties agreed to stipulate to the case proceeding as a class
action lawsuit regarding the issue of the correct payment methodology
to be applied in calculating the franchise fees due to the plaintiffs.
On March 14, 1995, the Superior Court granted PG&E's motion for
summary judgment in the class action lawsuit. The plaintiffs appealed
that ruling and on January 14, 1997, the Court of Appeal upheld the
summary judgment in PG&E's favor. The plaintiffs did not seek review
of the Court of Appeal's ruling, and accordingly, the summary judgment
has become final, resolving the issue of the payment methodology.
Consistent with the agreement between the parties as noted above, the
plaintiffs refiled a separate action covering just the issue of
whether PG&E properly calculated its franchise payments, assuming that
PG&E has been using the correct methodology. Plaintiffs' complaint
regarding whether PG&E properly calculated its franchise payments was
amended by stipulation to add claims that the payment by PG&E of
different amounts for the use of public streets and roads depending on
whether they lie within a city or a county constitutes an
"unreasonable discrimination" based solely on locality prohibited by
certain legislation. On July 31, 1997, the court sustained PG&E's
demurrer to the discrimination claims, dismissing these claims from
<PAGE>
the plaintiffs' complaint. The plaintiffs did not seek review of the
court's ruling, and accordingly, the dismissal of plaintiffs'
discrimination claims has become final.
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.
C. Cities Franchise Fees Litigation
As previously reported in the Corporation's and PG&E's Annual Report
on Form 10-K for the year ended December 31, 1996, a class action
lawsuit brought against PG&E on behalf of 107 cities with which PG&E
has certain electric franchise contracts has been pending in Santa
Cruz County Superior Court since 1994. The cities' complaint alleged
that, since at least 1987, PG&E intentionally underpaid its franchise
fees to the cities in an unspecified amount.
The complaint alleged that PG&E has applied the laws governing
electric franchises in an unlawfully discriminatory manner prohibited
by the Public Utilities Code, such that the cities in the class
receive lower franchise payments than other cities in PG&E's service
territory. The complaint also alleged that the transfer of these
franchises to PG&E by its predecessor companies was not approved by
the California Public Utilities Commission (CPUC) as required, and,
therefore, all such franchise contracts are void. On September 1,
1995, the Court bifurcated the issues in the case for trial such that
the issue concerning whether PG&E engaged in unlawful discrimination
in accepting certain franchise contracts with differing payment
formulas would be tried first, to be followed by the issues relating
to the validity of PG&E's current franchise contracts with the
plaintiff cities.
On January 22, 1996, the Court granted PG&E's motion for summary
judgment against five general law cities with respect to their
discrimination claims. The Court also granted various motions
effectively eliminating the claims of the class representative (the
City of Santa Cruz) and the other 30 charter cities by holding that
charter cities had no basis for their claims against PG&E since their
franchise fee structure was of their own choosing as a matter of "home
rule." Based on that ruling, on March 19, 1996, the Court granted
PG&E's motion to have judgment entered against the 31 charter cities
who are members of the plaintiff class. The plaintiff cities appealed
the Court's rulings.
On September 8, 1997, the Court of Appeal in San Jose unanimously
upheld the judgments in PG&E's favor against all 31 charter cities and
the 5 general law cities. With respect to the discrimination claim,
the appellate court agreed that the fact that PG&E follows the terms
of the 1937 Franchise Act cannot constitute "unreasonable
discrimination" prohibited by another statute. This decision applies
to all 107 plaintiff cities.
Further, with respect to the charter cities, the appellate court
agreed that the charter cities could not now be allowed to challenge
the franchise contracts that they granted freely. Although the
<PAGE>
charter cities are not compelled to follow any particular payment
formula, all 31 charter cities elected to adopt the 1937 Franchise Act
payment formula.
The plaintiffs have failed to appeal the appellate court's decision,
so the January and March 1996 rulings have become final.
The trial court in Santa Cruz County has set a status conference for
December 4, 1997, to decide how to handle the remaining issues
involving the 71 general law cities relating to the validity of PG&E's
current franchise fee contracts with those cities.
If the remaining 71 general law cities prevail, PG&E's annual system-
wide city electric franchise fees could increase by approximately $5
million, and damages for those remaining plaintiffs for alleged
underpayments in years 1987 through 1996 could be as much as $40
million (exclusive of interest, estimated to be $12.3 million as of
September 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 operation.
D. Norcen Litigation
Please refer to Part II, Item 1, of the Corporation and PG&E's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, for
a discussion of developments in this matter which was previously
reported in the Corporation and PG&E's Annual Report on Form 10-K for
the year ended December 31, 1996.
E. California Attorney General Investigation and Diablo Canyon
Environmental Litigation
Please refer to Part II, Item 1, of the Corporation and PG&E's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, for
a discussion of developments in this matter which was previously
reported in the Corporation and PG&E's Annual Report on Form 10-K for
the year ended December 31, 1996.
F. Compressor Station Chromium Litigation
Please refer to Part II, Item 1, of the Corporation and PG&E's
Quarterly Report on Form 10-Q for the quarter ended March 31, 1997,
for a discussion of developments in these matters which were
previously reported in the Corporation and PG&E's Annual Report on
Form 10-K for the year ended December 31, 1996.
G. Texas Franchise Fee Litigation
In connection with the Corporation's acquisition of Valero Energy
Corporation (Valero), now known as PG&E Gas Transmission, Texas
Corporation (GTT), GTT succeeded to the litigation described below.
1. City of Edinburg v. Rio Grande Valley Gas Co., Valero Energy
Corporation (now known as GTT), Valero Natural Gas Company (now known
<PAGE>
as PG&E Texas Natural Gas Company), Southern Union Gas Co., and
Southern Union Gas Co., Inc. (92nd State District Court, Hidalgo
County, Texas).
On August 31, 1995, the City of Edinburg (City) filed a lawsuit
against certain Valero and Southern Union companies. The City's
pleadings assert various contract and tort actions, but all such
claims are based on the theory that when Rio Grande Valley Gas Company
(RGVG), as the local distribution company (LDC), was granted a
franchise to sell gas and construct, maintain, own, and operate gas
pipelines in city streets, such authorization extended to RGVG and to
no other entity. (On September 30, 1993, Valero sold the common stock
of RGV to Southern Union.) The City seeks monetary and injunctive
damages on the theory that non-LDC owned pipelines were not authorized
under the franchise with RGVG and were otherwise unlawful without the
consent of, and the payment of compensation to, the City. The City
also claims that when RGVG began to operate pipelines it did not own,
such activities were not within the franchise and not otherwise
consented to by the City. Consequently, the City contends that all
non-LDC owned pipelines (which includes all of Valero Transmission,
L.P.'s transmission and gathering lines in City rights-of-way) are
"trespassing", and the Valero defendants must agree to a franchise or
face removal by injunction.
Further, the City contends that it is entitled to compensation for the
past presence of such pipelines in city property without consent, and
for the use of such pipelines to facilitate the past and present sales
of gas, both for resale and to direct end users, by any person or
entity other than the LDC. Additionally, the City contends that RGVG
has breached the franchise agreement by failing to pay all franchise
fees owed because it did not include in the "gross sales" figure such
incidental revenues as bad check fees, late payment charges, hook-up
and disconnect fees, and transportation revenues. The City seeks to
assert against the Valero defendants derivative liability for all of
RGVG's acts and omissions.
The latest pleading seeks actual damages in excess of $15 million,
unspecified punitive damages, and injunctive relief against six Valero
entities: Valero Energy Corporation (now known as GTT), Valero
Transmission Company (now known as PG&E Texas Pipeline Company),
Valero Natural Gas Company (now known as PG&E Natural Gas Company),
Reata Industrial Gas Company (now known as Valero Gas Marketing
Company), Valero Transmission, L.P. (now known as PG&E Texas Pipeline,
L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy,
L.P.), and two Southern Union entities: Southern Union Company ("SU")
and Mercado Gas Services, Inc.
Trial was originally set in the Edinburg matter for September 9, 1996,
but did not commence due to the disqualification on August 21, 1996,
of the original judge. The new judge has set a jury trial for June
15, 1998.
2. City of Mercedes v. Reata Industrial Gas, L.P. (now known as
PG&E Reata Energy, L.P.) and Reata Industrial Gas Company (now known
as Valero Gas Marketing Company) (92nd State District Court of Hidalgo
County, Texas).
<PAGE>
A lawsuit filed by the City of Mercedes on April 16, 1997, is
currently pending against Valero Gas Marketing Company and Reata
Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.). On
September 4, 1997, Mercedes amended its petition to include class
action claims and requested to be named as class representative for a
statewide class consisting of all Texas municipal corporations,
municipalities, towns, and villages, excluding the cities of Edinburg
and Weslaco (both of which filed separate actions), in which any of
the defendants have sold or supplied gas, or used public rights-of-way
to transport gas.
The defendants, gas marketers, have never had any ownership or
operation of any pipelines. Plaintiff asserts these marketing
companies have operated as "ghost pipelines" that have "used" public
property without consent or franchise from the cities in which the
defendants have sold gas. Plaintiff alleges that state law requires
the defendants have specific prior city consent by ordinance in order
to transact business in or through city limits. The plaintiff alleges
various tort and statutory claims against the defendants for failure
to secure such consent.
Plaintiff has requested a damage award, but has not specified an
amount.
Defendants' motion to transfer venue to Bexar County, Texas is
currently pending. On September 10, 1997, defendants also filed a
motion to disqualify or recuse the presiding judge of the 92nd State
District Court which is still pending. The disqualification/recusal
motion must be decided before the venue motions, plaintiffs' request
for class certification, or any other matters can be decided. If a
class is certified, defendants anticipate that they will challenge
such certification.
3. City of San Benito, City of Primera, and City of Port Isabel
v. Rio Grande Valley Gas Company, Valero Energy Corporation (now known
as GTT), Southern Union Company, et al., 107th State District Court,
Cameron County, Texas.
On December 31, 1996, a complaint was filed by the Texas cities of San
Benito, Primera, and Port Isabel against RGVG, Valero (now known as
GTT), Valero Natural Gas Company (now known as PG&E Texas Natural Gas
Company), Reata Industrial Gas Company (now known as Valero Gas
Marketing Company), Reata Industrial Gas L.P. (now known as PG&E Reata
Energy, L.P.), Valero Transmission L.P. (now known as PG&E Texas
Pipeline, L.P.), and Valero Transmission Company (now known as VT
Company), and two Southern Union entities: Southern Union Company
("SU") and Mercado Gas Services, Inc. On November 4, 1997, the cities
of San Benito, Primera, and Port Isabel filed an amended petition and
amended motion for class action certification, and dismissed the SU
defendants. The amended petition named as defendants GTT and all of
its subsidiaries (excluding the Canadian gas trading company and power
trading company), PG&E Gas Transmission Teco, Inc. and its
subsidiaries, and PG&E Energy Trading Corporation.
<PAGE>
In the amended petition, plaintiffs allege, among other things that
(i) the defendants that own or operate pipelines (in their capacities
as merchants or transporters) have occupied city property and
conducted pipeline operations without the cities' consent and without
compensating the cities for use of the cities' properties and (ii) the
defendants that are gas marketers have failed to pay cities for
accessing and utilizing pipelines located in the cities to flow gas
under city streets to end use gas customers. The petition also
alleges various tort and statutory claims against defendants for
failure to secure the consents.
On November 5, 1997, the court certified a class consisting of every
incorporated municipality in Texas (excepting the cities of Edinburg,
Mercedes, and Weslaco, which have filed separate actions) where any of
the defendants engaged in business activities related to natural gas
or natural gas liquids. The court named the cities of San Benito,
Primera, and Port Isabel as class representatives.
Defendants' motion to transfer venue of this case to Bexar County,
Texas is currently pending.
4. Other Franchise Fee Litigation
In addition to the three cases described above, involving the cities
of Edinburg, Mercedes, San Benito, Primera, and Port Isabel, there are
four lawsuits involving claims of a similar nature.
In 1996, the South Texas cities of Alton and Donna also independently
intervened as plaintiffs in the Edinburg lawsuit filed in the 92nd
State District Court in Hidalgo County. Subsequently, in July 1996,
these lawsuits were severed from the Edinburg lawsuit. The claims
asserted by the cities of Alton and Donna are substantially similar to
the Edinburg litigation claims. Damages are not quantified.
In December 1996, two additional lawsuits were filed in South Texas
making allegations substantially similar to those in the City of
Edinburg litigation: (City of La Joya v. Rio Grande Valley Gas
Company, Valero Energy Corporation, Southern Union Company, et al.,
92nd State District Court, Hidalgo County, Texas (filed December 27,
1996), and City of San Juan, City of La Villa, City of Penitas, City
of Edcouch, and City of Palmview v. Rio Grande Valley Gas Company,
Valero Energy Corporation, Southern Union Company, et al., 93rd State
District Court, Hidalgo County, Texas (filed December 27, 1996).)
The City of La Joya filed its lawsuit on its own behalf and as a
putative class representative on behalf of all similarly situated
cities against the same defendants sued in the Edinburg case. The
same Southern Union entities in the Edinburg suit have also been named
in this suit.
The factual allegations and claims asserted in the lawsuit filed by
the city of La Joya, and in the lawsuit filed by the cities of San
Juan, Lavilla, Penitas, Edcouch, and Palmview, are similar to the
claims made in the lawsuit filed by the cities of San Benito, Primera,
and Port Isabel. Defendants' motion to transfer venue of both cases
to Bexar County, Texas is also currently pending.
<PAGE>
Finally, on April 17, 1997, a complaint was filed by the South Texas
city of Weslaco. (City of Weslaco v. Reata Industrial Gas, L.P., et
al., 92nd State District Court, Hidalgo County, Texas). Weslaco sued
Valero Natural Gas Company (now known as PG&E Texas Natural Gas
Company), Reata Industrial Gas Company (now known as Valero Gas
Marketing Company) and Reata Industrial Gas, L.P. (now known as PG&E
Reata Energy L.P.) The causes of action alleged are identical to
those alleged in the City of Mercedes case. Defendants' motion to
transfer venue to Bexar County, Texas is currently pending.
Defendants have also filed a motion to disqualify or recuse the
presiding judge which is also pending.
The Corporation believes that the ultimate outcome of the Texas
franchise fee cases described above will not have a material adverse
impact on its financial position.
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 nine months ended
September 30, 1997, was 3.23. PG&E's earnings to combined fixed
charges and preferred stock dividends ratio for the nine months ended
September 30, 1997, was 2.99. 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 10.1 Asset Purchase Agreement by and among New England
Power Company, The Narragansett Electric Company,
and USGen Acquisition Corporation, dated as of
August 5, 1997 (1)
Exhibit 10.2* Agreement regarding certain payments between US
Generating Company and Joseph Kearney (1)
- ---------------------------
(1) Filed only as exhibits to the Quarterly Report on Form 10-Q
filed by PG&E Corporation under Commission File Number 1-12609.
*Management contract or compensatory plan or arrangement. Confidential
treatment of omitted information has been requested. Omitted
information has been filed separately with the Commission.
<PAGE>
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 nine months ended
September 30, 1997, for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the nine months ended
September 30, 1997, for PG&E
(b) Reports on Form 8-K during the third quarter of 1997 and
through the date hereof (2):
1. July 22, 1997
Item 5. Other Events
A. Performance Incentive Plan - Year to Date
Financial Results
2. August 6, 1997
Item 5. Other Events
A. Acquisitions
B. Gas Accord
3. September 10, 1997
Item 5. Other Events
A. Electric Industry Restructuring
4. September 16, 1997
Item 5. Other Events
A. California Public Utilities Commission Proceedings
5. October 16, 1997
Item 5. Other Events
A. Performance Incentive Plan - Year to Date
Financial Results
- ---------------------------
(2) 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
November 12, 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 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 nine months
ended September 30, 1997, for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the nine months
ended September 30, 1997, for PG&E
<PAGE>
<TABLE>
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
<CAPTION>
- ----------------------------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 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 $ 256,645 $ 225,416 $ 622,053 $ 581,344
========== ========== ========== ==========
Average common shares outstanding 414,358 411,759 406,875 413,738
========== ========== ========== ==========
EPS as shown in the Statement of
Consolidated Income $ 0.62 $ 0.55 $ 1.53 $ 1.41
========== ========== ========== ==========
PRIMARY EPS (1)
Net income for calculating primary EPS $ 256,645 $ 225,416 $ 622,053 $ 581,344
========== ========== ========== ==========
Average common shares outstanding 414,358 411,759 406,875 413,738
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) 254 4 202 10
---------- ---------- ---------- ----------
Average common shares outstanding as
adjusted 414,612 411,763 407,077 413,748
========== ========== ========== ==========
Primary EPS $ 0.62 $ 0.55 $ 1.53 $ 1.41
========== ========== ========== ==========
FULLY DILUTED EPS (1)
Net income for calculating fully diluted EPS $ 256,645 $ 225,416 $ 622,053 $ 581,344
========== ========== ========== ==========
Average common shares outstanding 414,358 411,759 406,875 413,738
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) 254 4 202 10
---------- ---------- ---------- ----------
Average common shares outstanding as
adjusted 414,612 411,763 407,077 413,748
========== ========== ========== ==========
Fully diluted EPS $ 0.62 $ 0.55 $ 1.53 $ 1.41
========== ========== ========== ==========
- ----------------------------------------------------------------------------------------------
<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>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
Ended -------------------------------------------------------
(dollars in thousands) 09/30/97 1996 1995 1994 1993 1992
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $579,553 $ 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 464,772 554,994 895,289 836,767 901,890 895,126
Net fixed charges 468,614 683,393 715,975 730,965 821,166 802,198
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $1,512,939 $1,996,084 $2,953,969 $2,572,418 $2,795,446 $2,864,556
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 368,164 $ 580,510 $ 627,375 $ 651,912 $ 731,610 $ 739,279
Interest on short-
term borrowings 81,235 75,310 83,024 77,295 87,819 61,182
Interest on capital
leases 1,440 3,508 2,735 1,758 1,737 1,737
Capitalized Interest 402 637 957 2,660 46,055 6,511
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned subsidiaries 17,775 24,319 3,306 - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges $ 469,016 $ 684,284 $ 717,397 $ 733,625 $ 867,221 $ 808,709
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 3.23 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>
- ----------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
ended ----------------------------------------------------------
(dollars in thousands) 09/30/97 1996 1995 1994 1993 1992
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 579,553 $ 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 464,772 554,994 895,289 836,767 901,890 895,126
Net fixed charges 468,614 683,393 715,975 730,965 821,166 802,198
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $1,512,939 $1,996,084 $2,953,969 $2,572,418 $2,795,446 $2,864,556
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 368,164 $ 580,510 $ 627,375 $ 651,912 $ 731,610 $ 739,279
Interest on short-
term debt 81,235 75,310 83,024 77,295 87,819 61,182
Interest on capital
leases 1,440 3,508 2,735 1,758 1,737 1,737
Capitalized Interest 402 637 957 2,660 46,055 6,511
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned subsidiaries 17,775 24,319 3,306 - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges $ 469,016 $ 684,284 $ 717,397 733,625 867,221 808,709
---------- ---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 7,543 10,057 11,343 4,672 4,814 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 29,331 39,108 99,984 96,039 108,937 130,147
---------- ---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 36,874 49,165 111,327 100,711 113,751 135,283
----------- ---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 505,890 $ 733,449 $ 828,724 $ 834,336 $ 980,972 $ 943,992
=========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.99 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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 20,353,222
<OTHER-PROPERTY-AND-INVEST> 730,821
<TOTAL-CURRENT-ASSETS> 3,885,903
<TOTAL-DEFERRED-CHARGES> 2,690,918
<OTHER-ASSETS> 1,753,883
<TOTAL-ASSETS> 29,414,747
<COMMON> 6,409,213
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2,612,048
<TOTAL-COMMON-STOCKHOLDERS-EQ> 9,021,261
437,500
390,591
<LONG-TERM-DEBT-NET> 8,181,912
<SHORT-TERM-NOTES> 12,256
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 1,320,523
<LONG-TERM-DEBT-CURRENT-PORT> 643,592
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 9,407,112
<TOT-CAPITALIZATION-AND-LIAB> 29,414,747
<GROSS-OPERATING-REVENUE> 10,511,317
<INCOME-TAX-EXPENSE> 457,569
<OTHER-OPERATING-EXPENSES> 9,048,440
<TOTAL-OPERATING-EXPENSES> 9,048,440
<OPERATING-INCOME-LOSS> 1,462,877
<OTHER-INCOME-NET> 138,403
<INCOME-BEFORE-INTEREST-EXPEN> 1,601,280
<TOTAL-INTEREST-EXPENSE> 496,823
<NET-INCOME> 646,888
24,835
<EARNINGS-AVAILABLE-FOR-COMM> 622,053
<COMMON-STOCK-DIVIDENDS> 358,947
<TOTAL-INTEREST-ON-BONDS> 306,112
<CASH-FLOW-OPERATIONS> 2,159,847
<EPS-PRIMARY> 1.53
<EPS-DILUTED> 1.53
</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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 17,484,072
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 2,828,874
<TOTAL-DEFERRED-CHARGES> 2,500,542
<OTHER-ASSETS> 1,081,782
<TOTAL-ASSETS> 23,895,270
<COMMON> 2,017,521
<CAPITAL-SURPLUS-PAID-IN> 2,563,693
<RETAINED-EARNINGS> 2,590,172
<TOTAL-COMMON-STOCKHOLDERS-EQ> 7,171,386
437,500
402,056
<LONG-TERM-DEBT-NET> 6,877,238
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 812,850
<LONG-TERM-DEBT-CURRENT-PORT> 427,030
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 7,767,210
<TOT-CAPITALIZATION-AND-LIAB> 23,895,270
<GROSS-OPERATING-REVENUE> 7,093,819
<INCOME-TAX-EXPENSE> 464,772
<OTHER-OPERATING-EXPENSES> 5,652,605
<TOTAL-OPERATING-EXPENSES> 5,652,605
<OPERATING-INCOME-LOSS> 1,441,214
<OTHER-INCOME-NET> 40,245
<INCOME-BEFORE-INTEREST-EXPEN> 1,481,459
<TOTAL-INTEREST-EXPENSE> 437,134
<NET-INCOME> 579,553
24,835
<EARNINGS-AVAILABLE-FOR-COMM> 554,718
<COMMON-STOCK-DIVIDENDS> 592,047
<TOTAL-INTEREST-ON-BONDS> 306,112
<CASH-FLOW-OPERATIONS> 1,919,280
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
