FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
----------------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended 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
---------- ----------
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 similar 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 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.
Exhibit 10.2* Agreement regarding certain payments between US
Generating Company and Joseph Kearney
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
*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>
ASSET PURCHASE AGREEMENT
BY AND AMONG
NEW ENGLAND POWER COMPANY,
THE NARRAGANSETT ELECTRIC COMPANY
AND
USGEN ACQUISITION CORPORATION
Dated As Of August 5, 1997
<PAGE>
ASSET PURCHASE AGREEMENT
-------------------------
ASSET PURCHASE AGREEMENT, dated as of August 5,
1997, by and among New England Power Company, a
Massachusetts corporation ("NEP"), The Narragansett
Electric Company, a Rhode Island corporation
("Narragansett," and together with NEP, the "Sellers"),
and USGen Acquisition Corporation, a Delaware corpoation
(the "Buyer").
WHEREAS, the Buyer desires to purchase, and the
Sellers desire to sell, the Fossil Assets and the
Hydroelectric Assets (each as defined herein and
together, the "Purchased Assets") upon the terms and
conditions hereinafter set forth in this Agreement;
NOW, THEREFORE, in consideration of the mutual
covenants, representations, warranties and agreements
hereinafter set forth, and intending to be legally bound
hereby, the parties hereto agree as follows:
ARTICLE I
DEFINITIONS
1.1. Definitions. (a) As used in this Agreement,
the following terms have the meanings specified in this
Section 1.1(a).
(1) "Affiliate" has the meaning set forth in Rule
12b-2 of the General Rules and Regulations under the
Exchange Act.
(2) "Allowance" means (i) an authorization by the
Administrator of the United States Environmental
Protection Agency under the Acid Rain Program to emit up
to one ton of sulfur dioxide during or after a specified
calendar year; or (ii) an authorization by the
Massachusetts Department of Environmental Protection or
the Rhode Island Department of Environmental Management
under the respective state Nitrogen Oxides ("NOx") Budget
Program authorizing the emission of up to one ton of NOx
during the ozone season, May 1 through September 1 of
each year.
<PAGE>
(3) "Ancillary Agreements" means the Continuing
Site Agreement, the PPA Transfer Agreement and the PSA
Performance Support Agreements.
(4) "Bill of Sale" means the Bill of Sale to be
delivered at the Closing, as the case may be, with
respect to the Purchased Assets which constitute personal
property and which are to be transferred at such Closing,
both substantially in the form of Exhibit A hereto.
(5) "Brayton Point" means the electric generation
facilities known as the Brayton Point Station and located
in Somerset, Massachusetts.
(6) "Business Day" shall mean any day other than
Saturday, Sunday and any day which is a legal holiday or
a day on which banking institutions in Boston are
authorized by law or other governmental action to close.
(7) "Buyer Representatives" means the Buyer's
accountants, employees, counsel, environmental
consultants, financial advisors and other authorized
representatives.
(8) "Capital Expenditures" means those capital
expenditures which are identified as capital expenditures
with respect to the projects identified on Schedule 7.1.
(9) "CERCLA" means the Federal Comprehensive
Environmental Response, Compensation and Liability Act.
(10) [Intentionally omitted.]
(11) [Intentionally omitted.]
(12) "COBRA" means the Consolidated Omnibus
Reconciliation Act of 1985, as amended.
(13) "Code" means the Internal Revenue Code of 1986,
as amended.
(14) "Confidentiality Agreement" means the
Confidentiality Agreement, dated December 13, 1996,
between NEES and U.S. Generating Company.
<PAGE>
(15) "Continuing Site Agreement" means the
Continuing Site/Interconnection Agreement, dated on the
date of this Agreement, between NEP and the Buyer.
(16) "Easements" means, with respect to the
Purchased Assets, the reservations of easements to be
included in the deeds of conveyance with respect to such
assets, substantially as set forth in Schedule 5.14
hereto.
(17) "Emission Reduction Credits" means credits, in
units that are established by the environmental
regulatory agency with jurisdiction over the facility
that has obtained the credits, resulting from a reduction
in the emissions of air pollutants from an emitting
source or facility (including, without limitation, and to
the extent allowable under applicable law, reductions
from shut-downs, control of emissions beyond that
required by applicable law, and fuel switching), that:
(i) have been certified by the Massachusetts Department
of Environmental Protection as complying with the law and
regulations of the Commonwealth of Massachusetts
governing the establishment of such credits (including,
without limitation, that such emissions reductions are
enforceable, permanent, quantifiable, real and surplus);
or (ii) have been certified by any other applicable
regulatory authority as complying with the law and
regulations governing the establishment of such credits
(including, without limitation, that such emissions
reductions are enforceable, permanent, quantifiable, real
and surplus). Emission Reduction Credits include
certified air emissions reductions, as described above,
regardless as to whether the regulatory agency certifying
such reductions designates such certified air emissions
reductions by a name other than "emissions reduction
credits."
(18) "Encumbrances" means any mortgages, pledges,
liens, security interests, conditional and installment
sale agreements, activity and use limitations,
conservation easements, deed restrictions, encumbrances
and charges of any kind.
(19) "Environmental Laws" means all Federal, state
and local laws, regulations, rules, ordinances, codes,
<PAGE>
decrees, judgments, directives, or judicial or
administrative orders relating to pollution or protection
of the environment, natural resources or human health and
safety, including, without limitation, laws relating to
Releases or threatened Releases of Hazardous Substances
(including, without limitation, ambient air, surface
water, groundwater, land, surface and subsurface strata)
or otherwise relating to the manufacture, processing,
distribution, use, treatment, storage, Release, transport
or handling of Hazardous Substances.
(20) "ERISA" means the Employee Retirement Income
Security Act of 1974, as amended.
(21) "Estimated Adjustment Amount" means the
Sellers' good faith reasonable estimate of an Adjustment
Amount for the Closing, which estimate shall be provided
to the Buyer no later than five Business Days before the
Closing.
(22) "Exchange Act" means the Securities Exchange
Act of 1934, as amended.
(23) "Federal Power Act" means the Federal Power Act
of 1935.
(24) "FERC" means the Federal Energy Regulatory
Commission.
(25) "FIRPTA Affidavit" means the Foreign Investment
in Real Property Tax Act Certification and Affidavit
substantially in the form of Exhibit C hereto.
(26) "Fossil Assets" means the Fossil Facilities,
the NERC Stock and the NEPGen Support Operation Assets.
(27) "Fossil Facilities" means, subject to the
Easements and Section 2.2, all of the right, title and
interest in, to and under the real and personal property,
tangible or intangible, owned by the Sellers and
constituting Brayton Point, Manchester Street and Salem
Harbor or used principally for generation purposes in
connection with Brayton Point, Manchester Street and
Salem Harbor including, but not limited to, the following
assets owned by the Sellers:
<PAGE>
(i) the Real Estate (including all buildings,
structures and other improvements thereon) described
on Schedule 5.14 as associated with Brayton Point,
Manchester Street and Salem Harbor (the "Fossil
Facilities Real Property");
(ii) all inventories of fuels, supplies, materials
and critical spares located on or in transit to the
Fossil Facilities Real Property on the Closing Date;
(iii) the machinery, equipment, vehicles, furniture
and other personal property located on the Fossil
Facilities Real Property on the Closing Date,
including, without limitation, the items of personal
property included in Schedule 1.1(a)(27)(iii) as being
associated with any of Brayton Point, Manchester
Street and Salem Harbor, and all warranties against
manufacturers or vendors relating thereto, to the
extent that such warranties are freely transferable;
(iv) the contracts, agreements and personal
property leases listed on Schedules 5.16(a) and
7.10(b) and (c) as being associated with any of
Brayton Point, Manchester Street and Salem Harbor and
which are assignable;
(v) the Transferable Permits listed on Schedule
1.1(a)(70) as being associated with any of Brayton
Point, Manchester Street and Salem Harbor;
(vi) all books, operating records, operating,
safety and maintenance manuals, engineering design
plans, blueprints and as-built plans, specifications,
procedures and similar items of the Sellers relating
specifically to the aforementioned assets other than
books of account;
(vii) Allowances, Emission Reduction Credits and
greenhouse gas reductions associated with (i) Brayton
Point, (ii) Manchester Street, (iii) Salem Harbor, or
(iv) the former electric generation facility known as
South Street Station and located in Providence, Rhode
Island that have accrued prior to, or that accrue on
or after, the date of this Agreement, including those
<PAGE>
set forth on Schedule 1.1(a)(27)(vii); but excluding
any Allowances, Emission Reduction Credits and
greenhouse gas reductions associated with the diesel
generators owned by Nantucket Electric;
(viii) any assets purchased or to be purchased by
the Sellers pursuant to Section 7.4(e).
(28) [Intentionally omitted]
(29) "Hazardous Substances" means (a) any
petrochemical or petroleum products, oil or coal ash,
radioactive materials, radon gas, asbestos in any form
that is or could become friable, urea formaldehyde foam
insulation and transformers or other equipment that
contain dielectric fluid which may contain levels of
polychlorinated biphenyls; (b) any chemicals, materials
or substances defined as or included in the definition of
"hazardous substances," "hazardous wastes," "hazardous
materials," "restricted hazardous materials," "extremely
hazardous substances," "toxic substances," "contaminants"
or "pollutants" or words of similar meaning and
regulatory effect; or (c) any other chemical, material or
substance, exposure to which is prohibited, limited or
regulated by any applicable Environmental Law.
(30) "Holding Company Act" means the Public Utility
Holding Company Act of 1935, as amended.
(31) "HSR Act" means the Hart-Scott-Rodino Antitrust
Improvements Act of 1976, as amended.
(32) "Hydroelectric Assets" means, subject to the
Easements and Section 2.2, all of the right, title and
interest in, to and under the real and personal property,
tangible or intangible, owned by NEP and constituting the
Bear Swamp Pumped Storage Station and the fourteen other
hydroelectric generating stations and associated dams and
reservoirs listed on Schedule 1.1(a)(32) as part of the
Hydroelectric Assets or used principally for generation
purposes in connection with such dams and reservoirs and
which are located within the applicable FERC project
license boundary, including, but not limited to, the
following assets owned by NEP:
<PAGE>
(i) the Real Estate (including all buildings,
structures and other improvements thereon) described
on Schedule 5.14 as associated with the Hydroelectric
Assets (the "Hydroelectric Real Property");
(ii) inventories of supplies, materials and
critical spares located on or in transit to the
Hydroelectric Real Property on the Hydroelectric
Assets Closing Date;
(iii) the machinery, equipment, vehicles, furniture
and other personal property located on the
Hydroelectric Real Property on the Closing Date,
including, without limitation, the items of personal
property included in Schedule 1.1(a)(32) as being
associated with the Hydroelectric Assets, and all
warranties against manufacturers or vendors relating
thereto, to the extent that such warranties are freely
transferable;
(iv) the contracts, agreements and personal
property leases listed on Schedules 5.16(a) and
7.10(b) and (c) as being associated with the
Hydroelectric Assets and which are assignable;
(v) the Transferable Permits listed on Schedule
1.1(a)(70) as being associated with the Hydroelectric
Assets;
(vi) all books, operating records, operating,
safety and maintenance manuals, engineering design
plans, blueprints and as-built plans, specifications,
procedures and similar items of NEP relating
specifically to the aforementioned assets other than
books of account;
(vii) all other Purchased Assets, if any, not
conveyed to the Buyer at the Closing; and
(viii) any assets purchased or to be purchased by
the Sellers pursuant to Section 7.4(e).
(33) [Intentionally omitted]
<PAGE>
(34) "Income Tax" means any federal, state, local or
foreign Tax (a) based upon, measured by or calculated
with respect to net income, profits or receipts
(including, without limitation, capital gains Taxes and
minimum Taxes) or (b) based upon, measured by or
calculated with respect to multiple bases (including,
without limitation, corporate franchise taxes) if one or
more of the bases on which such Tax may be based,
measured by or calculated with respect to, is described
in clause (a), in each case together with any interest,
penalties, or additions to such Tax.
(35) "Indentures" means (i) the General and
Refunding Mortgage Indenture and Deed of Trust, dated as
of January 1, 1977, as amended and supplemented, between
NEP and State Street Bank and Trust Company, as successor
trustee to Bank of New England, National Association
(formerly New England Merchants National Bank) and (ii)
the First Mortgage Indenture and Deed of Trust, dated as
of September 1, 1944, as amended and supplemented,
between Narragansett and Rhode Island Hospital Trust
Company.
(36) "Independent Accounting Firm" means Coopers &
Lybrand LLP or such other independent accounting firm of
national reputation mutually appointed by the Sellers and
the Buyer.
(37) "Instruments of Assumption" means the
Instrument of Assumption substantially in the form of
Exhibit D-1 hereto relating to the assumption by the
Buyer of the liabilities and obligations of the Sellers
described therein and the Instrument of Assumption
substantially in the form of Exhibit D-2 hereto relating
to the assumption by the Buyer of the liabilities and
obligations of the Sellers and NEPSCO under the Main
Table Agreements in each case, to be delivered at the
Closing.
(38) [Intentionally omitted]
(39) "Maintenance Expenditures" means those
maintenance expenditures which are identified as
maintenance expenditures with respect to the projects
identified on Schedule 7.1.
<PAGE>
(40) "Maintenance and Capital Expenditures Amount"
means the aggregate amount of all funds actually expended
on, or for which liabilities were accrued in accordance
with generally accepted accounting principles applied on
a consistent basis with respect to, Maintenance
Expenditures and Capital Expenditures by the Sellers, if
any, during the period beginning on the date hereof and
ending on the Closing Date.
(41) "Manchester Street" means the electric
generation facilities known as the Manchester Street
Station and located in Providence, Rhode Island.
(42) "Material Adverse Effect" means any change or
changes in, or effect on, the Purchased Assets after the
date of this Agreement that is, or in the aggregate are,
materially adverse to the business, assets, operations or
condition (financial or otherwise) of the Purchased
Assets, taken as a whole, other than (i) any change or
effect resulting from changes in the international,
national, regional or local wholesale or retail markets
for electric power, (ii) any change or effect resulting
from changes in the international, national, regional or
local markets for any fuel used at the Purchased Assets,
(iii) any change or effect resulting from changes in the
North American, national, regional or local electric
transmission systems and (iv) any materially adverse
change in or effect on the Purchased Assets which is
cured (including by the payment of money) by the Sellers
before the Termination Date; provided, however,
notwithstanding the foregoing, any change or effect
resulting from action by a legislative, governmental or
regulatory authority, other than any change or effect
resulting from the occurrence, non-occurrence,
acceleration or delay of Retail Access (as defined in
Section 3.4 hereof) which the Parties agree is fully
addressed by the Additional Payment Amount mechanism
provided in Section 3.4 hereof, shall be included in this
definition of Material Adverse Effect. The parties
hereto also agree that for purposes of measuring any
Material Adverse Effect (i) with respect to the Brayton
Point NPDES permit, the change or effect shall be
compared to the permit conditions prevailing under the
current NPDES permit and the Memorandum of Agreement II,
dated April 3, 1997, between and among the New England
<PAGE>
Office of the United States Environmental Protection
Agency, the Massachusetts Department of Environmental
Protection, the Massachusetts Executive Office of
Environmental Affairs, the Rhode Island Department of
Environmental Management and NEP relating to Brayton
Point whether or not the current NPDES permit is extended
or expires and (ii) any fact, circumstance or event which
the Sellers are required to disclose with respect to the
representations and warranties herein which are not
disclosed within this Agreement or the disclosure
schedules attached hereto shall be treated as if such
facts constituted a change or effect after the date of
this Agreement.
(43) "MDPU" means the Massachusetts Department of
Public Utilities.
(44) "NEES" means New England Electric System. The
name "New England Electric System" means the trustee or
trustees for the time being (as trustee or trustees but
not personally) under an Agreement and Declaration of
Trust dated January 2, 1926, as amended, which is hereby
referred to, and a copy of which, as amended, has been
filed with the Secretary of The Commonwealth of
Massachusetts. Any agreement, obligation, or liability
made, entered into, or incurred by or on behalf of New
England Electric System binds only its trust estate, and
no shareholder, director, trustee, officer, or agent
thereof assumes or shall be held to any liability
therefor.
(45) "NEPGen Support Operation Assets" means (i) the
machinery, personal property, software and other
equipment listed or referred to in Schedule 1.1(a)(45),
and all warranties against manufacturers or vendors
relating thereto, to the extent that such warranties are
freely transferable, (ii) the contracts, agreements and
personal property leases listed on Schedule 5.16(a) as
being associated with the NEPGen Support Operation Assets
and which are assignable, (iii) all books, operating
records, operating, safety and maintenance manuals,
engineering and design plans, specifications, procedures
and similar items of the Sellers relating specifically to
the aforementioned assets or, to the extent required by
law, to personnel employed at the aforementioned assets
who will become employees of the Buyer other than, in all
<PAGE>
cases, books of account, (iv) any assets purchased or to
be purchased by the Sellers pursuant to Section 7.4(e)
and (v) the Transferring Employee Records.
(46) "NERC" means Narragansett Energy Resources
Company, a Rhode Island corporation.
(47) "NERC Note Agreements" means the Note
Agreements, dated as of November 30, 1995, between (i)
NERC and Connecticut General Life Insurance Company, (ii)
NERC and Cigna Property and Casualty Insurance Company,
(iii) NERC and Insurance Company of North America and
(iv) NERC and Life Insurance Company of North America.
(48) "NERC Stock" means all of the issued and
outstanding common stock, par value $1.00 per share, of
NERC.
(49) "NHPUC" means the New Hampshire Public Utility
Commission.
(50) "NPDES" means the National Pollutant Discharge
Elimination System.
(51) "Permitted Encumbrances" means (i) those
Encumbrances set forth in Schedule 1.1(a)(51); (ii) the
Easements; (iii) those exceptions to title to the
Purchased Assets listed in Schedule 5.8; (iv) all
exceptions, restrictions, easements, charges, rights of
way and monetary and non-monetary encumbrances which are
set forth in an applicable FERC project license, except
for such encumbrances which secure indebtedness; (v) with
respect to any date before the Closing Date, Encumbrances
created by the Indentures or in connection with the NERC
Note Agreements; (vi) statutory liens for current taxes
or assessments not yet due or delinquent or the validity
of which is being contested in good faith by appropriate
proceedings; (vii) mechanics', carriers', workers',
repairers' and other similar liens arising or incurred in
the ordinary course of business relating to obligations
as to which there is no default on the part of the
Sellers or the validity of which are being contested in
good faith by appropriate proceedings; (viii) zoning,
entitlement, conservation restriction and other land use
and environmental regulations by governmental
authorities; and (ix) such other liens, imperfections in
<PAGE>
or failure of title, charges, easements, restrictions and
encumbrances which do not materially detract from the
value of the Purchased Assets as currently used or
materially interfere with the present use of the
Purchased Assets and neither secure indebtedness, nor
individually or in the aggregate create a Material
Adverse Effect.
(52) "Person" means any individual, a partnership, a
limited liability company, a joint venture, a
corporation, a trust, an unincorporated organization and
a governmental entity or any department or agency
thereof.
(53) "PPAs" means the Power Purchase Agreements
described in the PPA Transfer Agreement.
(54) "PPA Transfer Agreement" means the PPA Transfer
Agreement, dated on the date of this Agreement, between
NEP and the Buyer.
(55) "PSA Performance Support Agreements" mean the
PSA Performance Support Agreements, dated on the date of
this Agreement, each between NEP and the Buyer.
(56) "Release" means release, spill, leak,
discharge, dispose of, pump, pour, emit, empty, inject,
leach, dump or allow to escape into or through the
environment.
(57) "RIPUC" means the Rhode Island Public Utilities
Commission.
(58) "Salem Harbor" means the electric generation
facilities known as the Salem Harbor Station and located
in Salem, Massachusetts.
(59) "SEC" means the Securities and Exchange
Commission.
(60) "Securities Act" means the Securities Act of
1933, as amended.
(61) "Sellers' Agreements" means those agreements
listed on Schedule 5.16(a) and the Main Table Agreements
and BUW/CBAs (as defined in Schedule 7.10(c)).
<PAGE>
(62) "Settlement Agreements" means any agreement or
agreements that have been approved by the MDPU in Docket
No. 96-25 and by the FERC in Docket Nos. ER97-678-000 and
ER97-680-000, together with all conditions, terms or
modifications imposed by those agencies. Settlement
Agreements shall also include all agreements and orders
between NEP and Granite State Electric Company or other
non-Affiliate customers whether or not served under NEP's
FERC Electric Tariff No. 1 for all requirements service.
(63) "Specimen Title Policy" means for each of the
Purchased Assets constituting Real Estate, an ALTA 1987
form of owner's and/or mortgagee title insurance policy
jointly issued by Lawyers Title Insurance Corporation and
Fidelity National Title Insurance Company of New York
containing endorsements (including the standard co-
insurance endorsement substantially in the form of CLTA
114.2) and other coverages and exceptions, as more
particularly set forth in the pro forma title policies
attached hereto in Schedule 5.14.
(64) "Standard Offer Bid" means a bid submitted by
or on behalf of NEP into any request for proposals issued
by certain wholesale purchasers of electricity to supply
their customers with Standard Offer Service.
(65) "Standard Offer Service" means the electric
service, if any, required to be provided by a retail
electric distribution company to its retail customers who
do not elect to purchase electricity from an alternative
supplier in the market.
(66) "Subsidiary" when used in reference to any
other Person means any entity of which outstanding
securities having ordinary voting power to elect a
majority of the Board of Directors or other Persons
performing similar functions of such entity are owned
directly or indirectly by such other Person.
(67) "Tax Affiliate" means any entity that is a
member of an affiliated group of corporations (within the
meaning of Section 1504(a) of the Code) filing a
consolidated U.S. federal Income Tax Return, and a group
<PAGE>
of corporations filing a consolidated or combined Tax
Return for state, local or foreign purposes (each a
"Consolidated Group"), if NERC could be held liable for
the Taxes of such entity or Consolidated Group.
(68) "Taxes" means all taxes, charges, fees, levies,
penalties or other assessments imposed by any United
States federal, state or local or foreign taxing
authority, including, but not limited to, income, excise,
property, sales, transfer, franchise, payroll,
withholding, social security or other taxes, including
any interest, penalties or additions attributable
thereto.
(69) "Tax Return" means any return, report,
information return or other document (including any
related or supporting information) required to be
supplied to any authority with respect to Taxes.
(70) "Transferable Permits" means those Permits and
Environmental Permits which are transferable by the
Sellers to the Buyer and are set forth in Schedule
1.1(a)(70).
(71) "Transferring Employee Records" means all
personnel files related to the Sellers' personnel who
will become employees of the Buyer to the extent such
files pertain to (i) skill and development training and
resumes, (ii) seniority histories, (iii) salary and
benefit information, (iv) Occupational, Safety and Health
Administration medical reports, and (v) active medical
restriction forms.
(72) "Transition Agreements" means the Wholesale
Standard Offer Service Agreements, dated on the date of
this Agreement, between the Buyer, on the one hand, and
Narragansett, Massachusetts Electric Company and
Nantucket Electric Company on the other hand.
(73) "VTPSB" means the Vermont Public Service Board.
(74) "WARN Act" means the Federal Worker Adjustment
Retraining and Notification Act of 1988.
(75) "Wholesale Sales Agreement" means the Wholesale
Sales Agreement, dated on the date of this Agreement,
between the Buyer and NEP.
<PAGE>
(b) Each of the following terms has the
meaning specified in the Section set forth opposite such
term:
Term Section
- ---- -------
Additional Payment Amount 3.4(a)
Adjustment Amount 3.2(a)
Adjustment Statement 3.2(a)
Applicable Contracts 8.2(g)(3)
Assumed Obligations 2.3(c)
Audits 5.20(b)(v)
Benefit Plans 5.13(a)
BUW 7.10(a)
BUW CBAs 7.10(c)
BUW Employees 7.10(c)
BUW MOU 7.10(c)
Buyer Benefit Plans 7.10(f)
Buyer Required Regulatory Approvals 6.3(b)
Buyer Window 7.10(a)
Closing 4.1
Closing Date 4.1
Direct Claim 10.2(c)
Election 7.8(d)(1)(i)
Environmental Permits 5.11(a)
ERISA Affiliate 5.13(a)
ERISA Affiliate Plans 5.13(a)
Estimated Purchase Price 4.2(a)
Excluded Assets 2.2
Excluded Liabilities 2.4
Final Order 8.1(c)
Fossil Assets Conditions 4.1(a)
Fossil Employees 7.10(a)
Hydroelectric Assets Conditions 4.1(b)
Hydroelectric Employees 7.10(a)
IBEW 7.10(a)
IBEW/UWUA Employees 7.10(b)
IBEW/UWUA MOU 7.10(b)
Indemnifiable Loss 10.1(a)
Local Working Conditions 7.10(b)
Indemnifying Party 10.1(d)
Indemnitee 10.1(c)
Independent Appraiser 3.3(a)
Inventory Adjustment Amount 3.2(a)
<PAGE>
Inventory Survey 3.2(a)
Local Working Conditions 7.10(b)
Main Table Agreements 7.10(b)
Modified ADSP 7.8(d)(1)(ii)
NEES Intercompany Tax Allocation
Agreement 7.8(d)(2)(ii)
NEPGen Employee 7.10(a)
NEPSCO 8.2(f)
NEPGen Non-Union Employees 7.10(d)
NRC 5.3(b)
Observers 7.1(d)(i)
OSP 5.1(a)
OSP II 5.1(a)
Permits 5.18
Plans 7.10(a)
Prior Welfare Plans 7.10(e)
Purchased Assets Recitals
Purchase Price 3.1
Real Estate 5.14
Replacement Welfare Plans 7.10(e)
Sellers Balance Sheets 5.5
Sellers Required Regulatory
Approvals 5.3(b)
Sellers' Tax Returns 7.8(d)(2)(ii)
Severance Amount 3.1
Straddle Period 7.8(d)(2)(i)
Tax Contest 7.8(d)(4)(i)
Termination Date 11.1(b)(i)
Third Party Claim 10.2(a)
Transition Committee 7.1(c)
UWUA 7.10(a)
<PAGE>
ARTICLE II
PURCHASE AND SALE
------------------
2.1. The Sale. Upon the terms and subject to the
satisfaction of the conditions contained in this
Agreement, at the Closing the Sellers will sell, assign,
convey, transfer and deliver to the Buyer, and the Buyer
will purchase and acquire from Seller, free and clear of
all Encumbrances (except for Permitted Encumbrances) all
of the Sellers' right, title and interest in, to and
under the real and personal property, tangible or
intangible, owned by the Sellers and constituting the
Purchased Assets.
2.2. Excluded Assets. Notwithstanding any provision
herein to the contrary, the Purchased Assets shall not
include the following assets of the Sellers (herein
referred to as the "Excluded Assets"):
(a) all cash, cash equivalents, bank deposits,
accounts receivable, and any income, sales, payroll or
other tax receivables;
(b) certificates of deposit, shares of stock (other
than the NERC Stock), securities, bonds, debentures,
evidences of indebtedness, interests in joint ventures,
partnerships, limited liability companies and other
entities;
(c) the names "New England Electric System," "New
England Power Company," "New England Power," "NEES,"
"NEP," the "NEES companies," "The Narragansett Electric
Company" or any related or similar trade names,
trademarks, service marks or logos;
(d) the transmission, distribution, substation and
communication facilities and related support equipment
described or referred to in Schedule 2.2(d) or described
or referred to as an "Excluded Asset" or an asset of
"TCo" or "Seller" in the "Separation Document" (as
defined in the Continuing Site Agreement) or any document
or exhibit referred to or incorporated by reference in
the Separation Document or which are otherwise indicated
in any such document as remaining with the Sellers or any
of their Affiliates after the Closing;
<PAGE>
(e) any refund or credit (i) related to real or
personal property Taxes paid prior to the Closing Date in
respect of the Purchased Assets, whether such refund is
received as a payment or as a credit against future real
or personal property Taxes payable, or (ii) arising under
any PPA that is subject to cost of service regulation or
Sellers' Agreement and relating to a period before the
Closing Date;
(f) all personnel records other than Transferring
Employee Records or other records, the disclosure of
which is required by law, legal process or subpoena; and
(g) the Allowances and/or Emission Reduction
Credits listed on Schedule 2.2(g).
2.3. Assumed Obligations. (a) On the Closing Date,
the Buyer shall deliver to the Sellers the Instruments of
Assumption pursuant to which the Buyer shall assume and
agree to discharge all of the liabilities and obligations
of the Sellers, direct or indirect, known or unknown,
absolute or contingent, which relate to the Purchased
Assets, other than Excluded Liabilities, in accordance
with the respective terms and subject to the respective
conditions thereof, including, without limitation, the
following liabilities and obligations:
(i) all liabilities and obligations of the
Sellers under (a) the Sellers' Agreements, the real
property leases, and the Transferable Permits
associated with the Purchased Assets in accordance
with the terms thereof, (b) the contracts, leases and
other agreements entered into by the Sellers with
respect to the Purchased Assets which would be
required to be disclosed on Schedule 5.16(a) but for
the exception provided in clause (iii) of Section
5.16(a) of this Agreement, in accordance with the
terms thereof, and (c) the contracts, leases and other
agreements entered into by the Sellers with respect to
the Purchased Assets after the date hereof consistent
with the terms of this Agreement (including, without
limitation, agreements with respect to liabilities for
real or personal property Taxes on any of the
<PAGE>
Purchased Assets or, to the extent such agreements do
not allocate such Tax liability between the Purchased
Assets and the Excluded Assets, all Tax liability
under such agreements, subject to the covenants of
Seller pursuant to Section 7.8(f) hereof, entered into
by the Sellers and any local government); except in
each case, to the extent such liabilities and
obligations, but for a breach or default by the
Sellers, would have been paid, performed or otherwise
discharged on or prior to the Closing Date or to the
extent the same arise out of any such breach or
default or out of any event which after the giving of
notice would constitute a default;
(ii) all liabilities and obligations associated
with the Purchased Assets in respect of Taxes for
which the Buyer is liable pursuant to Section 3.5 or
7.8(a);
(iii) any liabilities and obligations associated
with the Purchased Assets for which the Buyer has
indemnified the Sellers pursuant to Section 10.1;
(iv) all liabilities and obligations with respect
to the NEPGen Employees to be employed at the
Purchased Assets after the Closing Date for which the
Buyer is responsible pursuant to Section 7.10;
(v) any liability, obligation or responsibility
under or related to former, current or future
Environmental Laws or the common law, whether such
liability or obligation or responsibility is known or
unknown, contingent or accrued, arising as a result of
or in connection with (a) any violation or alleged
violation of Environmental Law, prior to the Closing
Date, with respect to the ownership or operation of
the Purchased Assets; (b) loss of life, injury to
persons or property or damage to natural resources
(whether or not such loss, injury or damage arose or
was made manifest before the Closing Date or arises or
becomes manifest after the Closing Date), caused (or
allegedly caused) by the presence or Release of
Hazardous Substances at, on, in, under, adjacent to or
migrating from the Purchased Assets prior to the
Closing Date, including, but not limited to, Hazardous
<PAGE>
Substances contained in building materials at the
Purchased Assets or in the soil, surface water,
sediments, groundwater, landfill cells, or in other
environmental media at or adjacent to the Purchased
Assets; and (c) the investigation and/or remediation
(whether or not such investigation or remediation
commenced before the Closing Date or commences after
the Closing Date) of Hazardous Substances that are
present or have been Released prior to the Closing
Date at, on, in, under, adjacent to or migrating from
the Purchased Assets, including, but not limited to,
Hazardous Substances contained in building materials
at the Purchased Assets or in the soil, surface water,
sediments, groundwater, landfill cells, or in other
environmental media at or adjacent to the Purchased
Assets; provided, as to all of the above, that nothing
set forth in this subsection 2.3(a) shall require the
Buyer to assume any liabilities that are expressly
excluded in Section 2.4; provided further, however
that nothing set forth in this subsection 2.3(a) shall
require the Buyer to assume any obligation for payment
of any fines or penalties imposed by a governmental
agency to the extent such obligations arise out of or
relate to acts or omissions of the Sellers that
constitute criminal violations;
(vi) any liability, obligation or responsibility
under or related to former, current or future
Environmental Laws or the common law, whether such
liability or obligation or responsibility is known or
unknown, contingent or accrued, arising as a result of
or in connection with (a) any violation or alleged
violation of Environmental Law, on or after the
Closing Date, with respect to the ownership or
operation of the Purchased Assets; (b) compliance with
applicable Environmental Laws on or after the Closing
Date with respect to the ownership or operation of the
Purchased Assets; (c) loss of life, injury to persons
or property or damage to natural resources caused (or
allegedly caused) by the presence or Release of
Hazardous Substances at, on, in, under, adjacent to or
migrating from the Purchased Assets on or after the
Closing Date, including, but not limited to, Hazardous
Substances contained in building materials at or
adjacent to the Purchased Assets or in the soil,
<PAGE>
surface water, sediments, groundwater, landfill cells,
or in other environmental media at the Purchased
Assets; (d) loss of life, injury to persons or
property or damage to natural resources caused (or
allegedly caused) by the off-site disposal, storage,
transportation, discharge, Release, recycling, or the
arrangement for such activities, of Hazardous
Substances, on or after the Closing Date, in
connection with the ownership or operation of the
Purchased Assets; (e) the investigation and/or
remediation of Hazardous Substances that are present
or have been released on or after the Closing Date at,
on, in, under, adjacent to or migrating from the
Purchased Assets, including, but not limited to,
Hazardous Substances contained in building materials
at the Purchased Assets or in the soil, surface water,
sediments, groundwater, landfill cells or in other
environmental media at or adjacent to the Purchased
Assets; and (f) the investigation and/or remediation
of Hazardous Substances that are disposed, stored,
transported, discharged, Released, recycled, or the
arrangement of such activities, on or after the
Closing Date, in connection with the ownership or
operation of the Purchased Assets, at any off-site
location; provided, that nothing set forth in this
subsection shall require the Buyer to assume any
liabilities that are expressly excluded in Section
2.4;
(vii) all liabilities and obligations of the
Sellers, including, but not limited to air emissions
commitments, associated with the Purchased Assets
under the Settlement Agreements;
(viii) all liabilities and obligations of the
Sellers with respect to the Purchased Assets under the
agreements or consent orders set forth on Schedule
5.11;
(ix) all liabilities incurred by the Sellers with
respect to Maintenance Expenditures and Capital
Expenditures associated with the Purchased Assets but
only to the extent such liabilities were not included
in the Maintenance and Capital Expenditures Amount;
<PAGE>
and with respect to the Purchased Assets, (a) any Tax
that may be imposed by any state or local government
on the ownership, sale, operation or use of the
Purchased Assets on or after the Closing Date; except
for any Income Taxes attributable to income (including
proceeds representing the Purchase Price or proceeds
of other asset sales) received by the Sellers and (b)
real or personal property Taxes to the extent assumed
by the Buyer pursuant to Section 3.5.
(b) All of the foregoing liabilities and
obligations to be assumed by the Buyer under Section
2.3(a) (excluding any Excluded Liabilities) are referred
to herein as the "Assumed Obligations." It is understood
and agreed that nothing in this Section 2.3 shall
constitute a waiver or release of any claims arising out
of the contractual relationships between the Sellers and
the Buyer.
2.4. Excluded Liabilities. The Buyer shall not
assume or be obligated to pay, perform or otherwise
discharge the following liabilities or obligations:
(i) any liabilities or obligations of the Sellers
in respect of any Excluded Assets or other assets of
the Sellers which are not Purchased Assets;
(ii) any liabilities or obligations in respect of
Taxes attributable to the Purchased Assets for taxable
periods ending on or before the Closing Date, except
for Taxes for which the Buyer is liable pursuant to
Section 3.5 or Section 7.8(a);
(iii) any liabilities, obligations, or
responsibilities relating to the disposal, storage,
transportation, discharge, Release, recycling, or the
arrangement for such activities, by the Sellers, of
Hazardous Substances that were generated at the Fossil
Assets, at any off-site location, where the disposal,
storage, transportation, discharge, Release, recycling
or the arrangement for such activities at said off-
site location occurred prior to the Closing Date,
provided that for purposes of this Section, "off-site
location" does not include any location to which
Hazardous Substances disposed of or Released at the
Fossil Assets have migrated;
<PAGE>
(iv) any liabilities, obligations, or
responsibilities relating to the disposal, storage,
transportation, discharge, Release, recycling, or the
arrangement for such activities, by the Sellers, of
Hazardous Substances that were generated at the
Hydroelectric Assets, at any off-site location, where
the disposal, storage, transportation, discharge,
Release, recycling or the arrangement for such
activities at said off-site location occurred prior to
the Closing Date, provided that for purposes of this
Section, "off-site location" does not include any
location to which Hazardous Substances disposed of or
Released at the Hydroelectric Assets have migrated;
(v) any liabilities, obligations or
responsibilities relating to (a) the property,
equipment or machinery within the switchyards for
which the Sellers will retain an Easement, (b) the
Brayton Point step-up transformers, including, without
limitation, liabilities related to the disposal,
discharge or Release of Hazardous Substances, whether
such liabilities, obligations or responsibilities
arose from the ownership or operation of said
property, equipment or machinery or the Brayton Point
step-up transformers prior to or after the Closing
Date unless caused by the Buyer's operations or
equipment, (c) the transmission lines delineated in
the Easements or (d) any Seller's operations on, or
usage of, the Easements, including, without
limitation, liabilities, obligations or
responsibilities arising as a result of or in
connection with (1) any violation or alleged violation
of Environmental Law and (2) loss of life, injury to
persons or property or damage to natural resources,
except to the extent caused by Buyer;
(vi) any liabilities or obligations required to be
accrued by the Sellers in accordance with generally
accepted accounting principles and the FERC Uniform
System of Accounts (A) on or before the Closing Date
with respect to liabilities related to the Purchased
Assets other than any liability assumed by Buyer under
Section 2.3(a)(v) or (vi);
<PAGE>
(vii) any liabilities or obligations relating to
any personal injury, discrimination, wrongful
discharge, unfair labor practice or similar claim or
cause of action filed with or pending before any court
or administrative agency on the Closing Date, with
respect to liabilities principally relating to the
Fossil Assets or with respect to liabilities
principally relating to the Hydroelectric Assets, or
any such potential claim or incident set forth in
Schedule 2.4;
(viii) any fines or penalties imposed by a
governmental agency resulting from (A) an
investigation or proceeding pending on or prior to the
Closing Date or (B) illegal acts, willful misconduct
or gross negligence of the Sellers prior to the
Closing Date;
(ix) any payment obligations of the Sellers for
goods delivered or services rendered prior to the
Closing;
(x) any liabilities or obligations resulting from
the Sellers' gross negligence or willful misconduct
other than any liability assumed by the Buyer under
Section 2.3(a)(v) or (vi) hereof;
(xi) any liabilities or obligations imposed upon,
assumed or retained by the Sellers or any of their
Affiliates pursuant to the Continuing Site Agreement
or any other Ancillary Agreement;
(xii) any liabilities, obligations or
responsibilities relating to any Benefit Plan or any
"employee pension benefit plan" (as defined in Section
3(2) of ERISA) maintained by any of the Sellers and
any trade or business (whether or not incorporated)
which are or have ever been under common control, or
which are or have ever been treated as a single
employer, with any of the Sellers under Section
414(b), (c), (m) or (o) of the Code ("ERISA
Affiliate") or to which any of the Sellers and any
ERISA Affiliate contributed thereunder (the "ERISA
Affiliate Plans"), including any multiemployer plan,
maintained by, contributed to, or obligated to
<PAGE>
contribute to, at any time, by the Sellers or any
ERISA Affiliate, including any liability (A) to the
Pension Benefit Guaranty Corporation under Title IV of
ERISA; (B) relating to a multiemployer plan; (C) with
respect to non-compliance with the notice and benefit
continuation requirements of COBRA; (D) with respect
to any non-compliance with ERISA or any other
applicable laws; or (E) with respect to any suit,
proceeding or claim which is brought against the
Buyer, any Benefit Plan, ERISA Affiliate Plan, any
fiduciary or former fiduciary of any such Benefit Plan
or ERISA Affiliate Plan; and
(xiii) any liabilities, obligations or
responsibilities relating to the employment or
termination of employment, including a constructive
termination, by the Sellers of any individual
(including, but not limited to, any employee of the
Sellers) attributable to any actions or inactions by
the Sellers prior to the Closing Date other than such
actions or inactions taken at the direction of the
Buyer.
All such liabilities and obligations not being
assumed pursuant to Section 2.4 are herein called the
"Excluded Liabilities."
ARTICLE III
PURCHASE PRICE
3.1. Purchase Price. The purchase price for the
Purchased Assets shall be an amount equal to the sum of
(a) $1,365,000,000, (b) the Adjustment Amount, (c) an
amount (the "Severance Amount") equal to $85,000,000
relating to the costs of the Sellers for voluntary early
retirements and pre-Closing employee severance packages,
(d) any amounts paid pursuant to Section 7.4(e) hereof
and (e) any amount payable at the Closing pursuant to
Section 4.2(c)(i) or thereafter pursuant to Section
4.2(c)(ii) hereof (the "Purchase Price").
3.2. Purchase Price Adjustment. (a) Within 30 days
after the Closing, the Sellers shall prepare and deliver
to the Buyer a statement (each, an "Adjustment
<PAGE>
Statement") which reflects (i) the net book value, as
reflected on the books of the Sellers as of the Closing
Date of all fuel inventory (FERC account no. 151) (less,
in the case of fuel inventory, any amount carried on
NEP's books in respect of losses incurred by New England
Energy Incorporated) and stores inventory (FERC account
no. 154) used at or in connection with either the Fossil
Assets or the Hydroelectric Assets, as the case may be
(the "Inventory Adjustment Amount"), and (ii) the
Maintenance and Capital Expenditures Amount applicable to
the Fossil Assets or the Hydroelectric Assets, as the
case may be. The Inventory Adjustment Amount and the
Maintenance and Capital Expenditures Amount for the
Closing is referred to collectively as the "Adjustment
Amount." The Inventory Adjustment Amount will be based
on an inventory survey conducted within five days prior
to the Closing Date consistent with current NEP inventory
procedures (the "Inventory Survey"). The Sellers will
permit an employee, or representative, of the Buyer to
observe the Inventory Survey. Each Adjustment Statement
shall be prepared using the same generally accepted
accounting principles, policies and methods as the
Sellers have historically used in connection with the
calculation of the items reflected on such Adjustment
Statement. The Buyer agrees to cooperate with the
Sellers in connection with the preparation of each
Adjustment Statement and related information, and shall
provide to the Sellers such books, records and
information as may be reasonably requested from time to
time.
(b) The Buyer may dispute an Inventory Adjustment
Amount or a Maintenance and Capital Expenditures Amount;
provided, however, that the Buyer shall notify the
Sellers in writing of the disputed amount, and the basis
of such dispute, within ten (10) Business Days of the
Buyer's receipt of the applicable Adjustment Statement.
In the event of a dispute with respect to any part of an
Adjustment Amount, the Buyer and the Sellers shall
attempt to reconcile their differences and any resolution
by them as to any disputed amounts shall be final,
binding and conclusive on the parties. If the Buyer and
the Sellers are unable to reach a resolution of such
differences within 30 days of receipt of the Buyers'
written notice of dispute to the Sellers, the Buyer and
the Sellers shall submit the amounts remaining in dispute
<PAGE>
for determination and resolution to the Independent
Accounting Firm, which shall be instructed to determine
and report to the parties, within 30 days after such
submission, upon such remaining disputed amounts, and
such report shall be final, binding and conclusive on the
parties hereto with respect to the amounts disputed. The
fees and disbursements of the Independent Accounting Firm
shall be allocated between the Buyer and the Sellers so
that the Buyer's share of such fees and disbursements
shall be in the same proportion that the aggregate amount
of such remaining disputed amounts so submitted by the
Buyer to the Independent Accounting Firm that is
unsuccessfully disputed by the Buyer (as finally
determined by the Independent Accounting Firm) bears to
the total amount of such remaining disputed amounts so
submitted by the Buyer to the Independent Accounting
Firm.
(c) Within ten (10) Business Days after the
Buyer's receipt of an Adjustment Statement, the Buyer
shall pay all undisputed amounts, or if there is a
dispute with respect to any amount on such Adjustment
Statement within five (5) Business Days after the final
determination of any amounts on such Adjustment
Statement, the Buyer shall pay to NEP on behalf of the
Sellers an amount equal to the disputed Adjustment Amount
as finally determined to be payable with respect to such
Adjustment Statement. All Adjustment Statement payments
shall be less the Estimated Adjustment Amount; provided,
however, that if such amount shall be less than zero then
the Sellers will pay to the Buyer the amount by which
such amount is less than zero. Any amount paid under
this Section 3.2(c) shall be paid with interest for the
period commencing on the Closing Date through the date of
payment, calculated at the prime rate of the Bank of
Boston in effect on the Closing Date, and in cash by
federal or other wire transfer of immediately available
funds.
3.3. Allocation of Purchase Price. (a) The Buyer
and the Sellers shall use their good faith best efforts
to agree upon an allocation among the Purchased Assets of
the sum of the Purchase Price and the Assumed Obligations
consistent with Section 1060 of the Code and the Treasury
Regulations thereunder within 180 days of the date of
this Agreement but in no event less than 30 days prior to
<PAGE>
the Closing. The Buyer and the Sellers may jointly agree
to obtain the services of an independent engineer or
appraiser (the "Independent Appraiser") to assist the
parties in determining the fair value of the Purchased
Assets for purposes of such allocation. If such an
appraisal is made, both the Buyer and the Sellers agree
to accept the Independent Appraiser's determination of
the fair value of the Purchased Assets. The parties
shall jointly select the Independent Appraiser. The cost
of the appraisal shall be borne equally by the Buyer and
the Sellers. Each of the Buyer and the Sellers agree to
file Internal Revenue Service Form 8594, and all federal,
state, local and foreign Tax Returns, in accordance with
such agreed allocation. Each of the Buyer and the
Sellers shall report the transactions contemplated by the
Agreement for federal Income Tax and all other tax
purposes in a manner consistent with the allocation
determined pursuant to this Section 3.3. Each of the
Buyer and the Sellers agrees to provide the other
promptly with any other information required to complete
Form 8594. Each of the Buyer and the Sellers shall
notify and provide the other with reasonable assistance
in the event of an examination, audit or other proceeding
regarding the agreed upon allocation of the Purchase
Price.
(b) With respect to the sale of the NERC Stock,
the Buyer and the Sellers shall allocate that portion of
the Purchase Price which is attributable to the NERC
Stock in accordance with the Election.
3.4. Additional Payment Amount.
(a) The Buyer shall pay the Seller an additional
purchase price of $225,000,000 (the "Additional Payment
Amount") as adjusted in the manner described below:
(i) if the Retail Choice Date (as defined below)
occurs after the later of the Closing or January 1,
1999 and prior to January 1, 2000, the Additional
Payment Amount shall be reduced by $75,000,000
multiplied by (x) the number of days in the calendar
year 1999 before the Retail Choice Date divided by (y)
365;
(ii) if the Retail Choice Date occurs on or after
January 1, 2000 and prior to January 1, 2003, the
<PAGE>
Additional Payment Amount shall be reduced by (A)
$75,000,000 plus (B) $50,000,000 multiplied by (x) the
number of days from January 1, 2000 to the Retail
Choice Date divided by (y) 365.
(iii) if the Retail Choice Date occurs on or after
January 1, 2003, the Additional Payment Amount shall
be zero.
(b) The "Retail Choice Date" shall be defined as
the date on which Retail Access (as defined below) is
first available to either (i) customers representing 89%
of the 1995 kilowatthour sales of investor-owned
utilities in Massachusetts or (ii) customers (including
those of Massachusetts Electric Company) representing 50%
of the 1995 kilowatthour sales of utilities in New
England. "Retail Access" shall mean the ability of
retail electric customers to purchase electric power
directly from power generators, power marketers, or any
other entities at prices not subject to regulation.
3.5. Proration. (a) The Buyer and the Sellers
agree that all of the items normally prorated, including
those listed below, relating to the business and
operation of the Purchased Assets will be prorated as of
the Closing Date, with the Sellers liable to the extent
such items relate to any time period through the Closing
Date, and the Buyer liable to the extent such items
relate to periods subsequent to the Closing Date:
(i) personal property, real estate,
occupancy, sewerage and water Taxes, assessments and
other charges, if any, on or with respect to the
business and operation of the Purchased Assets;
(ii) rent, Taxes and all other items payable
by or to the Sellers under any of the PPAs that are
subject to cost of service regulation and under any of
the Sellers' Agreements assigned to and assumed by the
Buyer hereunder which are associated with the
Purchased Assets;
(iii) any permit, license, registration,
compliance assurance fees or other fees with respect
to any Transferable Permit associated with the
Purchased Assets;
<PAGE>
(iv) sewer rents and charges for water,
telephone, electricity and other utilities; and
(v) rent under any leases of real or
personal property included in the Purchased Assets,
including the leases described in Schedule 5.9.
(b) In connection with the prorations referred to
in (a) above, in the event that actual figures are not
available at the Closing Date, the proration shall be
based upon the actual Taxes or fees for the preceding
year (or appropriate period) for which actual Taxes or
fees are available and such Taxes or fees shall be
reprorated upon request of either the Sellers, on the one
hand, or the Buyer, on the other hand, made within sixty
(60) days of the date that the actual amounts become
available. The Sellers and the Buyer agree to furnish
each other with such documents and other records as may
be reasonably requested in order to confirm all
adjustment and proration calculations made pursuant to
this Section 3.5.
ARTICLE IV
THE CLOSING
4.1. Time and Place of Closing. (a) Upon the terms
and subject to the satisfaction of the conditions
contained in Article VIII of this Agreement (the "Fossil
Assets Conditions") and the conditions contained in
Article IX of this Agreement (the "Hydroelectric Assets
Conditions"), the closing of the sale of the Purchased
Assets contemplated by this Agreement (the "Closing")
will take place at the offices of Skadden, Arps, Slate,
Meagher & Flom LLP, 919 Third Avenue, New York, New York
10022, at 10:00 A.M. (local time) on such date as the
parties may agree which date is as soon as practicable,
but no later than fifteen Business Days, following the
date on which all of the Hydroelectric Assets Conditions
and the Fossil Assets Conditions have been satisfied or
waived; or at such other place or time as the parties may
agree. The date and time at which the Closing actually
occurs is hereinafter referred to as the "Closing Date."
<PAGE>
4.2. Payment of Purchase Price. (a) Upon the terms
and subject to the satisfaction of the conditions
contained in this Agreement, in consideration of the
aforesaid sale, assignment, conveyance, transfer and
delivery of the Purchased Assets, the Buyer will pay or
cause to be paid to NEP on behalf of the Sellers at the
Closing an amount (the "Estimated Purchase Price") in
United States dollars equal to the sum of (i)
$1,365,000,000, (ii) the Estimated Adjustment Amount for
the Closing, (iii) the Severance Amount, (iv) any amounts
expended by the Sellers pursuant to Section 7.4(e) hereof
and (vi) any amounts payable under Section 4.2(c) hereof,
by wire transfer of immediately available funds or by
such other means as are agreed upon by the Sellers and
the Buyer; and
(b) [intentionally left blank]
(c) Upon the terms and subject to the satisfaction
of the conditions contained in this Agreement, in
consideration of the aforesaid sale, assignment,
conveyance, transfer and delivery of the Purchased
Assets, the Buyer will pay or cause to be paid to NEP on
behalf of the Sellers, the Additional Payment Amount, as
set forth in Section 3.4 hereof:
(i) if, prior to the Closing Date, either (A) the
Retail Choice Date shall have occurred and legislation
authorizing Retail Access shall have been enacted in
Massachusetts or (B) legislation has been enacted in
Massachusetts which provides for the Retail Choice
Date to occur on or prior to January 1, 1999, then the
Additional Payment Amount shall be paid on the Closing
Date; and
(ii) if the conditions required in subsection 4.2
(c) (i) for the payment of the Additional Payment
Amount were not met on the Closing Date, then such
payment will be made in United States dollars by wire
transfer of immediately available funds or by such
other means are agreed upon by the Sellers and the
Buyer, within five (5) Business Days of the delivery
of a certificate executed by duly authorized officers
of the Sellers, certifying that the Retail Choice Date
has occurred and either (A) legislation authorizing
<PAGE>
Retail Access has been enacted in Massachusetts and
the requirements for the Retail Choice Date shall have
been met continuously from such date through the date
of enactment of such legislation or (B) the
requirements for the Retail Choice Date have been in
continuous effect for at least two years from the
Retail Choice Date and a material portion of the
customers enjoying Retail Access are not participants
in pilot programs. If payment of the Additional
Payment Amount is made after the later of the Retail
Choice Date or the Closing Date, the Buyer will also
pay the Seller, concurrent with the payment of the
Additional Payment Amount, an interest payment for the
period elapsed since the later of the Retail Choice
Date and the Closing, on the amount of the Additional
Payment Amount, at an annual interest rate equal to
the sum of the yield (i) reported on page PX1 of the
Bloomberg Financial Market Services Screen (or, if not
available, any other nationally recognized trading
screen reporting on-line intraday trading in the
United States government Securities) at 4:00 p.m. (New
York time) three business days prior to the date on
which payment of the Additional Payment Amount is
made, for the off the run Treasury Bill or Note with a
maturity equivalent to the length of time since the
later of the Retail Choice Date and the Closing plus
(ii) 0.40%. If no maturity exactly corresponds to
such period, the yields for the two published
maturities most closely corresponding to such period
shall be interpolated or extrapolated from such yields
on a straight line basis.
4.3. Deliveries by the Sellers. At the Closing,
the Sellers will deliver the following to the Buyer:
(a) A Bill of Sale, duly executed by the Sellers
for the personal property included in the Purchased
Assets;
(b) All consents, waivers or approvals obtained by
the Seller with respect to the Purchased Assets, the
transfer of any Transferable Permit related to the
Purchased Assets, or the consummation of the transactions
connected to the sale of the Purchased Assets,
contemplated by this Agreement, to the extent
specifically required hereunder;
<PAGE>
(c) An opinion of counsel and certificate (as
contemplated by Section 8.2 and 9.2) with respect to the
Purchased Assets;
(d) One or more deeds of conveyance of the Real
Estate (substantially as set forth in Schedule 5.14
hereto) related to the Purchased Assets, to the Buyer,
reserving the applicable Easements, duly executed and
acknowledged by the Sellers and in recordable form;
(e) A FIRPTA Affidavit executed by each of the
Sellers;
(f) All such other instruments of assignment or
conveyance as shall, in the reasonable opinion of the
Buyer and its counsel, be necessary to transfer to the
Buyer the Purchased Assets, in accordance with this
Agreement and where necessary or desirable, in recordable
form; and
(g) Such other agreements, documents, instruments
and writings as are required to be delivered by the
Sellers at or prior to the Closing Date pursuant to this
Agreement or otherwise required in connection herewith.
4.4. Deliveries by the Buyer. At the Closing, the
Buyer will deliver the following to the Sellers:
(a) The Estimated Purchase Price by wire transfer
of immediately available funds or such other means as are
agreed upon by the Sellers and the Buyer;
(b) Opinions of counsel and certificates (as
contemplated by Section 8.3 and 9.3) with respect to the
Purchased Assets;
(c) The Instruments of Assumption with respect to
the Assumed Obligations, duly executed by the Buyer;
(d) All such other instruments of assumption as
shall, in the reasonable opinion of the Sellers and its
counsel, be necessary for the Buyer to assume the Assumed
Obligations related to the Purchased Assets in accordance
with this Agreement; and
<PAGE>
(e) Such other agreements, documents, instruments
and writings as are required to be delivered by the Buyer
at or prior to the Closing Date pursuant to this
Agreement or otherwise required in connection herewith.
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF THE SELLERS
The Sellers represent and warrant to the Buyer as
follows (all such representations and warranties, except
those regarding the Sellers, being made to the best
knowledge of the Sellers after reasonable inquiry or
investigation). Notwithstanding anything in this
Agreement to the contrary, Narragansett makes no
representations other than as to itself and as relates to
Manchester Street.
5.1. Organization; Qualification; Matters Regarding
NERC. (a) NEP is a corporation duly organized, validly
existing and in good standing under the laws of the
Commonwealth of Massachusetts and has all requisite
corporate power and authority to own, lease, and operate
its properties and to carry on its business as is now
being conducted. Narragansett and NERC are corporations
duly organized, validly existing and in good standing
under the laws of the State of Rhode Island and have all
requisite corporate power and authority to own, lease,
and operate their properties and to carry on their
businesses as are now being conducted. The Sellers are
duly qualified or licensed to do business as foreign
corporations and are in good standing in each
jurisdiction in which the property owned, leased or
operated by them or the nature of the business conducted
by them makes such qualification necessary, except in
each case in those jurisdictions where the failure to be
so duly qualified or licensed and in good standing would
not create a Material Adverse Effect. The Sellers and
NERC have heretofore delivered to the Buyer complete and
correct copies of their Certificates of Incorporation and
Bylaws as currently in effect.
(b) The authorized capital stock of NERC consists
of one (1) share of common stock, par value $1.00 per
<PAGE>
share, one share of which is issued and outstanding.
Such share of NERC Stock has been duly authorized and
validly issued, is fully paid and non-assessable, and has
not been issued in violation of the preemptive rights of
any stockholder of NERC. At the Closing, NEP will be the
record and beneficial owner of full right and title to
such share of NERC Stock, free and clear of all
Encumbrances, options, warrants, rights, calls, pledges,
trusts, voting trusts and other stockholder agreements,
assessments, covenants, restrictions, reservations,
commitments, obligations, liabilities, and other burdens.
Assuming issuance by the SEC of an appropriate order
under the Holding Company Act, as of the Closing NEP will
have the absolute and unrestricted right, power,
authority and capacity to sell the NERC Stock to the
Buyer.
(c) NERC owns general partnership interests
representing 20% of the aggregate partnership interests
in each of Ocean State Power, a Rhode Island general
partnership ("OSP"), and Ocean State Power II, a Rhode
Island general partnership ("OSP II"), free and clear of
all Encumbrances except for Permitted Encumbrances. NERC
(i) was organized solely for purposes of acting as a
general partner in OSP, owns no other assets and has no
liabilities of any kind, except as attributable to
(A) such general partnership interests, other than those
arising in the ordinary course of business that are not
material, and (B) occasional liabilities to NEPSCO, tax
liabilities to NEES under the NEES Intercompany Tax
Allocation Agreement, and the NERC Note Agreements, all
of which will be discharged on or prior to the Closing
(ii) does not engage, and has never engaged in, any
business other than holding such general partnership
interests, and (iii) does not have, and has never had,
any employees.
5.2. Authority Relative to this Agreement. The
Sellers have full corporate power and authority to
execute and deliver this Agreement and to consummate the
transactions contemplated hereby. The execution and
delivery of this Agreement and the consummation of the
transactions contemplated hereby have been duly and
validly authorized by the Boards of Directors of the
Sellers and will, prior to the Closing, be duly and
validly authorized by the stockholders of NEP with
<PAGE>
general voting rights and, assuming defeasance of the
General and Refunding Mortgage Indenture and Deed of
Trust, dated as of January 1, 1977, as amended and
supplemented, between NEP and State Street Bank and Trust
Company, as successor trustee to Bank of New England,
National Association (formerly New England Merchants
National Bank) and the issuance by the SEC of an order
authorizing the transaction contemplated hereby, no other
corporate proceedings on the part of the Sellers are
necessary to authorize this Agreement or to consummate
the transactions contemplated hereby. This Agreement has
been duly and validly executed and delivered by the
Sellers, and assuming that this Agreement constitutes a
valid and binding agreement of the Buyer, subject to the
receipt of the Sellers Required Regulatory Approvals and
the Buyer Required Regulatory Approvals, constitutes a
valid and binding agreement of the Sellers, enforceable
against the Sellers in accordance with its terms, except
that such enforceability may be limited by applicable
bankruptcy, insolvency, moratorium or other similar laws
affecting or relating to enforcement of creditors' rights
generally or general principles of equity.
5.3. Consents and Approvals; No Violation. (a)
Except as set forth in Schedule 5.3, and other than
obtaining the Sellers Required Regulatory Approvals and
the Buyer Required Regulatory Approvals, neither the
execution and delivery of this Agreement by the Sellers
nor the sale by the Sellers of the Purchased Assets
pursuant to this Agreement will (i) conflict with or
result in any breach of any provision of the Certificates
of Incorporation or Bylaws of the Sellers, (ii) require
any consent, approval, authorization or permit of, or
filing with or notification to, any governmental or
regulatory authority, except (x) where the failure to
obtain such consent, approval, authorization or permit,
or to make such filing or notification, would not,
individually or in the aggregate, create a Material
Adverse Effect or (y) for those requirements which become
applicable to the Sellers as a result of the specific
regulatory status of the Buyer (or any of its Affiliates)
or as a result of any other facts that specifically
relate to the business or activities in which the Buyer
(or any of its Affiliates) is or proposes to be engaged;
(iii) result in a default (or give rise to any right of
termination, cancellation or acceleration) under any of
<PAGE>
the terms, conditions or provisions of any note, bond,
mortgage, indenture, license, agreement or other
instrument or obligation to which the Sellers are a party
or by which the Sellers, or any of the Purchased Assets
may be bound, except for such defaults (or rights of
termination, cancellation or acceleration) as to which
requisite waivers or consents have been obtained or
which, in the aggregate, would not, individually or in
the aggregate, create a Material Adverse Effect; or (iv)
violate any order, writ, injunction, decree, statute,
rule or regulation applicable to the Sellers, or any of
their assets, which violation, individually or in the
aggregate, would create a Material Adverse Effect.
(b) Except as set forth in Schedule 5.3 and except
for (i) any required approvals under the Federal Power
Act, (ii) (A) notice by NEP to, and an order by, the MDPU
approving the transactions contemplated by this
Agreement, (B) the approval by the RIPUC of the market
valuation "implementation methodology" filed in RIPUC
Docket 2540, pursuant to section 39-1-27.4(g) of the
Rhode Island General Laws, (C) the approval by the RIPUC
of the "Transfer Plan" filed in RIPUC Docket 2515,
pursuant to section 39-1-27(a) of the Rhode Island
General Laws, (D) the approval, if required, of the Rhode
Island Division of Public Utilities and Carriers of the
transfer of Manchester Street to Buyer, (E) the approval,
if required, of the Rhode Island Energy Facilities Siting
Board of the transfer of Manchester Street to the Buyer,
(F) if required, notice by NEP to, and an order by, each
of the NHPUC and the VTPSB approving the sale of the
Hydroelectric Assets, (iii) the approval, if required, of
the SEC pursuant to the Holding Company Act, (iv) the
filings by the Sellers and the Buyer required by the HSR
Act and the expiration or earlier termination of all
waiting periods under the HSR Act, and (v) the approval,
if required, of the Nuclear Regulatory Commission (the
"NRC") (the filings and approvals referred to in clauses
(i) through (v) are collectively referred to as the
"Sellers Required Regulatory Approvals"), no declaration,
filing or registration with, or notice to, or
authorization, consent or approval of any governmental or
regulatory body or authority is necessary for the
consummation by the Sellers of the transactions
contemplated hereby, other than such declarations,
filings, registrations, notices, authorizations, consents
<PAGE>
or approvals which, if not obtained or made, will not,
individually or in the aggregate, create a Material
Adverse Effect.
5.4. Reports. Since January 1, 1994, the Sellers
have filed or caused to be filed with the SEC, the
applicable state or local utility commissions or
regulatory bodies, the NRC or the FERC, as the case may
be, all material forms, statements, reports and documents
(including all exhibits, amendments and supplements
thereto) required to be filed by them with respect to the
business and operations of the Sellers as it relates to
the Purchased Assets under each of the Securities Act,
the Exchange Act, the applicable State public utility
laws, the Federal Power Act, the Holding Company Act, and
the Price-Anderson Act and the respective rules and
regulations thereunder, all of which complied in all
material respects with all applicable requirements of the
appropriate act and the rules and regulations thereunder
in effect on the date each such report was filed, and
there are no material misstatements or omissions in
respect of such reports.
5.5. Financial Statements. Sellers have made
available to the Buyer their balance sheets, as of June
30, 1997. Such balance sheets (including the related
notes thereto) are referred to herein as the "Sellers
Balance Sheets." Each of the Sellers Balance Sheets
presents fairly, as of June 30, 1997, the financial
position of such Seller in conformity with generally
accepted accounting principles applied on a consistent
basis, except as otherwise noted therein.
5.6. Undisclosed Liabilities. Except as set forth
in Schedule 5.6, the Sellers have no liability or
obligation relating to the business or operations of the
Purchased Assets, secured or unsecured (whether absolute,
accrued, contingent or otherwise, and whether due or to
become due), of a nature required by generally accepted
accounting principles as they have been consistently
applied by the Sellers to be reflected in a corporate
balance sheet or disclosed in the notes thereto, which
are not accrued or reserved against in the Sellers
Balance Sheets or disclosed in the notes thereto in
accordance with generally accepted accounting principles,
<PAGE>
except those which either were incurred in the ordinary
course of business, whether before or after the date of
the Sellers Balance Sheets.
5.7. Absence of Certain Changes or Events. Except
(i) as set forth in Schedule 5.7, or in the reports,
schedules, registration statements and definitive proxy
statements filed by any of the Sellers or NEES with the
SEC and (ii) as otherwise contemplated by this Agreement,
since the date of the Sellers Balance Sheets there has
not been: (a) any Material Adverse Effect; (b) any
damage, destruction or casualty loss, whether covered by
insurance or not, which, individually or in the
aggregate, created a Material Adverse Effect; (c) any
entry into any agreement, commitment or transaction
(including, without limitation, any borrowing, capital
expenditure or capital financing) by the Sellers or NERC,
which is material to the business or operations of the
Purchased Assets, except agreements, commitments or
transactions in the ordinary course of business that in
the aggregate are not material to the Purchased Assets or
as contemplated herein; or (d) any change by the Sellers,
with respect to the Purchased Assets or NERC, in
accounting methods, principles or practices except as
required or permitted by generally accepted accounting
principles.
5.8. Title and Related Matters. Except as set
forth in Schedule 5.8 and except for Permitted
Encumbrances, the Sellers have marketable title to the
Real Estate as specified in the Specimen Title Policy for
each of the Purchased Assets constituting Real Estate.
Except as set forth in Schedule 5.8 and except for
Permitted Encumbrances, the Sellers have good and valid
title to the other Purchased Assets which they purport to
own that are reflected in the Sellers Balance Sheets
(other than those which have been disposed of since the
date thereof in the ordinary course of business), free
and clear of all Encumbrances.
5.9. Leases. Schedule 5.9 lists, as of the date of
this Agreement, all real property leases under which the
Sellers are a lessee or lessor and which (x) are to be
transferred and assigned to the Buyer on the Closing Date
and (y) (i) provide for annual payments of more than
$500,000 or (ii) are material to the business, operations
<PAGE>
or financial condition of the Purchased Assets. Except
as set forth in Schedule 5.9, all such leases are valid,
binding and enforceable in accordance with their terms,
and are in full force and effect; there are no existing
material defaults by the Sellers or, to the Sellers'
knowledge, any other party thereunder; and no event has
occurred which (whether with or without notice, lapse of
time or both) would constitute a material default by the
Sellers or, to the Sellers' knowledge, any other party
thereunder.
5.10. Insurance. Except as set forth in Schedule
5.10, all material policies of fire, liability, worker's
compensation and other forms of insurance owned or held
by the Sellers and insuring the Purchased Assets are in
full force and effect, all premiums with respect thereto
covering all periods up to and including the date as of
which this representation is being made have been paid
(other than retroactive premiums which may be payable
with respect to comprehensive general liability and
worker's compensation insurance policies), and no notice
of cancellation or termination has been received with
respect to any such policy which was not replaced on
substantially similar terms prior to the date of such
cancellation. Except as described in Schedule 5.10, as
of the date of this Agreement, the Sellers have not been
refused any insurance with respect to the Purchased
Assets nor has their coverage been limited by any
insurance carrier to which they have applied for any such
insurance or with which they have carried insurance
during the last twelve months.
5.11. Environmental Matters. Except as disclosed
in Schedule 5.11 or in any public filing by any of the
Sellers or NEES pursuant to the Securities Act or the
Exchange Act:
(a) The Sellers hold, and are in substantial
compliance with, all material permits, licenses and
governmental authorizations ("Environmental Permits")
required for the Sellers to conduct the business and
operations of the Purchased Assets under applicable
Environmental Laws, and the Sellers are otherwise in
compliance with applicable Environmental Laws with
respect to the business and operations of the Purchased
Assets except for such failures to hold or comply with
<PAGE>
required Environmental Permits, or such failures to be in
compliance with applicable Environmental Laws, which,
individually or in the aggregate, are not reasonably
likely to create a Material Adverse Effect;
(b) The Sellers have not received any written
request for information, or been notified that they are a
potentially responsible party, under CERCLA or any
similar State law with respect to any on-site location,
except for such liability under such laws as would not be
reasonably likely to, individually or in the aggregate,
create a Material Adverse Effect; and
(c) The Sellers have not entered into or agreed to
any consent decree or order, and are not subject to any
outstanding judgment, decree, or judicial order relating
to compliance with any Environmental Law or to
investigation or cleanup of Hazardous Substances under
any Environmental Law, except for such consent decree or
order, judgment, decree or judicial order that would not
be reasonably likely to, individually or in the
aggregate, create a Material Adverse Effect.
The representations and warranties made in this Section
5.11 are the Sellers' exclusive representations and
warranties relating to environmental matters.
5.12. Labor Matters. The Sellers have previously
delivered to the Buyer copies of all collective
bargaining agreements to which the Sellers are a party or
are subject and which relate to the business or
operations of the Purchased Assets. Solely (in each of
the following clauses (a) through (f)) with respect to
the business or operations of the Purchased Assets,
except to the extent set forth in Schedule 5.12 and
except for such matters as will not, individually or in
the aggregate, create a Material Adverse Effect (a) the
Sellers are in compliance with all applicable laws
respecting employment and employment practices, terms and
conditions of employment and wages and hours; (b) the
Sellers have not received written notice of any unfair
labor practice complaint against the Sellers pending
before the National Labor Relations Board; (c) there is
no labor strike, slowdown or stoppage actually pending or
threatened against or affecting the Sellers; (d) the
Sellers have not received notice that any representation
<PAGE>
petition respecting the employees of the Sellers has been
filed with the National Labor Relations Board; (e) no
arbitration proceeding arising out of or under collective
bargaining agreements is pending against the Sellers and
(f) the Sellers have not experienced any primary work
stoppage since at least December 31, 1994.
5.13. ERISA; Benefit Plans. (a) Schedule 5.13(a)
lists all deferred compensation, profit-sharing,
retirement and pension plans, including multiemployer
plans (of which none exist), and all material bonus and
other employee benefit or fringe benefit plans maintained
or with respect to which contributions are made by the
Sellers in respect to current or former employees
employed at the Purchased Assets ("Benefit Plans").
Accurate and complete copies of all such Benefit Plans
have been made available to the Buyer.
(b) Except as set forth in Schedule 5.13(b), the
Sellers and the ERISA Affiliates have fulfilled their
respective obligations under the minimum funding
requirements of Section 302 of ERISA, and Section 412 of
the Code, with respect to each Benefit Plan which is an
"employee pension benefit plan" as defined in Section
3(2) of ERISA and each such plan is in compliance in all
material respects with the presently applicable
provisions of ERISA and the Code. Except as set forth in
Schedule 5.13(b), neither the Sellers nor any ERISA
Affiliate has incurred any liability under Section
4062(b) of ERISA to the Pension Benefit Guaranty
Corporation in connection with any Benefit Plan which is
subject to Title IV of ERISA, nor any withdrawal
liability nor is there any reportable event (as defined
in Section 4043 of ERISA) except as set forth in Schedule
5.13(b). Except as set forth in Schedule 5.13(b), the
Internal Revenue Service has issued a letter for each
Benefit Plan which is intended to be qualified
determining that such plan is exempt from United States
Federal Income Tax under Sections 401(a) and 501(a) of
the Code, and there has been no occurrence since the date
of any such determination letter which has adversely
affected such qualification.
(c) None of the Sellers nor any ERISA Affiliate or
parent corporation, within the meaning of Section 4069(b)
or Section 4212(c) of ERISA, has engaged in any
<PAGE>
transaction, within the meaning of Section 4069(b) or
Section 4212(c) of ERISA. No Benefit Plan and no ERISA
Affiliate Plan is a multiemployer plan.
(d) Each of the Sellers that maintains a "group
health plan" within the meaning of Section 5000(b)(1) of
the Code has materially complied in good faith with the
notice and continuation requirements of Section 4980B of
the Code, COBRA, Part 6 of Subtitle B of Title I of ERISA
and the regulations thereunder.
5.14. Real Estate. Schedule 5.14 contains a
description of, and exhibits indicating the location of,
the real property owned by the Sellers and included in
the Purchased Assets (the "Real Estate"). Schedule 5.14
also describes any indebtedness secured by a mortgage or
other Encumbrance on the Real Estate. Complete and
correct copies of any current surveys in the Sellers'
possession or any policies of title insurance currently
in force and in the possession of the Sellers with
respect to such real property have heretofore been
delivered by the Sellers to the Buyer.
5.15. Condemnation. Except as set forth in
Schedule 5.15, neither the whole nor any part of the Real
Estate or any other real property or rights leased, used
or occupied by the Sellers in connection with the
ownership or operation of the Purchased Assets is subject
to any pending suit for condemnation or other taking by
any public authority, and, no such condemnation or other
taking has been threatened.
5.16. Certain Contracts and Arrangements. (a)
Except (i) as listed in Schedule 5.16(a) or any other
Schedule to this Agreement, (ii) for contracts,
agreements, personal property leases, commitments,
understandings or instruments which will expire prior to
the Closing Date, and (iii) for agreements with suppliers
entered into in the ordinary course of business that are
not material to the Purchased Assets, the Sellers are not
a party to any written contract, agreement, personal
property lease, commitment, understanding or instrument
which is material to the business or operations of the
Purchased Assets, and NERC is not a party to any such
contract which is material to the business or operations
of OSP and OSP II.
<PAGE>
(b) Except as disclosed in Schedule 5.16(b), each
of the PPAs and each material Sellers' Agreement (i)
constitutes a valid and binding obligation of NEP or
Narragansett, as the case may be, and to the best
knowledge of the Sellers constitutes a valid and binding
obligation of the other parties thereto, (ii) is in full
force and effect, and (iii) may be transferred to the
Buyer pursuant to this Agreement and will continue in
full force and effect thereafter, in each case without
breaching the terms thereof or resulting in the
forfeiture or impairment of any rights thereunder.
(c) Except as set forth in Schedule 5.16(c), there
is not, under any of the PPAs or the Sellers' Agreements,
any default or event which, with notice or lapse of time
or both, would constitute a default on the part of any of
the parties thereto, except, with respect to the Sellers'
Agreements only, such events of default and other events
as to which requisite waivers or consents have been
obtained or which would not, individually or in the
aggregate, create a Material Adverse Effect.
(d) If the Continuing Site Agreement were in full
force and effect between Sellers' generation business and
Sellers' transmission business on the date of this
Agreement, (i) the Sellers' generation business would be
in material compliance with the terms thereof, and (ii)
there is no event or condition that would enable or
require the Seller's transmission business to (x) notify
the Sellers' generation business of the necessity of an
addition to or modification of the Interconnection
Facilities, as defined in Section 3.1.4 of the Continuing
Site Agreement, (y) operate and/or purchase from the
Sellers' generation business any of the equipment or
facilities specified in section 3.2.8(d) of the
Continuing Site Agreement, or (z) discontinue
Interconnection Service under Section 3.13.1 of the
Continuing Site Agreement, as defined therein.
5.17. Legal Proceedings, etc. Except as set forth
in Schedule 5.17 or in any filing made by NEES or the
Sellers pursuant to the Securities Act or the Exchange
Act, there are no claims, actions, proceedings or
investigations pending or threatened against or relating
<PAGE>
to the Sellers before any court, governmental or
regulatory authority or body acting in an adjudicative
capacity, which, if adversely determined, individually or
in the aggregate, would create a Material Adverse Effect.
Except as set forth in Schedule 5.17 or in any filing
made by NEES or the Sellers pursuant to the Securities
Act or the Exchange Act, the Sellers are not subject to
any outstanding judgment, rule, order, writ, injunction
or decree of any court, governmental or regulatory
authority which, individually or in the aggregate, would
create a Material Adverse Effect.
5.18. Permits. (b) The Sellers have all permits,
licenses, franchises and other governmental
authorizations, consents and approvals, other than with
respect to Environmental Laws (collectively, "Permits")
necessary to operate the business of the Purchased Assets
as presently conducted, except where the failure to have
such Permits would not, individually or in the aggregate,
create a Material Adverse Effect. Except as set forth in
Schedule 5.18(a), the Sellers have not received any
written notification that they are in violation of any of
such Permits, or any law, statute, order, rule,
regulation, ordinance or judgment of any governmental or
regulatory body or authority applicable to it, except for
notifications of violations which would not, individually
or in the aggregate, create a Material Adverse Effect.
The Sellers are in compliance with all Permits, laws,
statutes, orders, rules, regulations, ordinances, or
judgments of any governmental or regulatory body or
authority applicable to it, except for violations which,
individually or in the aggregate, do not create a
Material Adverse Effect.
(b) Schedule 5.18(b) sets forth all material
Permits and Environmental Permits other than Transferable
Permits (which are set forth on Schedule 1.1(a)(70)).
5.19. Regulation as a Utility. Each of the Sellers
is a public utility company within the meaning of the
Holding Company Act. Except as set forth on Schedule
5.19, the Sellers are not subject to regulation as a
public utility or public service company (or similar
designation) by the United States, any state of the
United States, any foreign country or any municipality or
any political subdivision of the foregoing.
<PAGE>
5.20. Taxes. (a) With respect to the Purchased
Assets and trades or businesses associated with the
Purchased Assets other than the NERC Stock, (i) all Tax
Returns required to be filed other than those Tax Returns
the failure of which to file would not create a Material
Adverse Effect have been filed, and (ii) all material
Taxes shown to be due on such Tax Returns have been paid
in full. Except as set forth in Schedule 5.20, no notice
of deficiency or assessment has been received from any
taxing authority with respect to liabilities for Taxes of
the Sellers in respect of the Purchased Assets, which
have not been fully paid or finally settled, and any such
deficiency shown in such Schedule 5.20 is being contested
in good faith through appropriate proceedings. Except as
set forth in Schedule 5.20, there are no outstanding
agreements or waivers extending the applicable statutory
periods of limitation for Taxes associated with the
Purchased Assets for any period. Schedule 5.20 sets
forth the taxing jurisdictions in which the Sellers own
assets or conduct business that require a notification to
a taxing authority of the transactions contemplated by
this Agreement, if the failure to make such notification,
or obtain Tax clearances in connection therewith, would
either require the Buyer to withhold any portion of the
Purchase Price or would subject Buyer to any liability
for any Taxes of the Sellers.
(b) With respect to the sale of the NERC Stock,
except as set forth on Schedule 5.20:
(i) NERC has (x) duly and timely filed (or there
has been filed on its behalf) with the appropriate
taxing authorities all Tax Returns required to be
filed by it, and all such Tax Returns are true,
correct and complete and (y) timely paid or there has
been paid on its behalf all Taxes due or claimed to be
due from it by any taxing authority;
(ii) NERC has, within the time and manner
prescribed by law, withheld and paid over to the
proper governmental authorities all amounts required
to be withheld and paid over under all applicable
laws;
<PAGE>
(iii) There are no Encumbrances for Taxes upon the
assets or properties of NERC, except for statutory
Encumbrances for current Taxes not yet due;
(iv) NERC has not requested any extension of time
within which to file any Tax Return in respect of any
taxable year which has not since been filed and no
outstanding waivers or comparable consents regarding
the application of the statute of limitations with
respect to any Taxes or Tax Returns has been given by
or on behalf of NERC;
(v) No federal, state, local or foreign audits or
other administrative proceedings or court proceedings
("Audits") exist or have been initiated with regard to
any Taxes or Tax Returns of NERC and NERC has not
received any written notice that such an audit is
pending or threatened with respect to any Taxes due
from or with respect to NERC or any Tax Return filed
by or with respect to NERC;
(vi) NERC has not requested or received a ruling
from any taxing authority or signed a closing or other
agreement with any taxing authority which could have a
material adverse effect on NERC;
(vii) The Tax Returns of NERC have been examined by
the appropriate taxing authorities (or the applicable
statute of limitations for the assessment of Taxes for
such periods have expired) for all periods through and
including the date of this Agreement and a list of all
Audits commenced or completed with respect to NERC for
all taxable periods not yet closed by the statute of
limitations are set forth on Schedule 5.20;
(viii) All Tax deficiencies which have been claimed,
proposed or asserted against NERC have been fully paid
or finally settled, and no issue has been raised in
any examination which, by application of similar
principles, could be expected to result in the
proposal or assertion of a Tax deficiency for any
other year not so examined;
(ix) Except for the NEES Intercompany Tax
Allocation Agreement, NERC is not a party to, is not
<PAGE>
bound by, and has no obligation under, any Tax sharing
agreement, Tax indemnification agreement or similar
contract or arrangement;
(x) No power of attorney has been granted with
respect to NERC as to any matter relating to Taxes;
(xi) NERC has not filed a consent pursuant to
Section 341(f) of the Code (or any predecessor
provision) or agreed to have Section 341(f)(2) of the
Code apply to any disposition of a subsection (f)
asset, as such term is defined in Section 341(f)(4) of
the Code, owned by NERC;
(xii) No property owned by NERC (A) is property
required to be treated as being owned by another
Person pursuant to the provisions of Section 168(f)(8)
of the Internal Revenue Code of 1954, as amended and
in effect immediately prior to the enactment of the
Tax Reform Act of 1986, (B) constitutes "tax-exempt
use property" within the meaning of Section 168(h)(1)
of the Code or (C) is tax-exempt bond financed
property within the meaning of Section 168(g) of the
Code;
(xiii) Since December 31, 1996, NERC has not
incurred any liability for Taxes other than in the
ordinary course of business;
(xiv) NERC has no liability for Taxes of any person
pursuant to Treasury Regulation Section 1.1502-6 (or
any similar provision of state, local or foreign law)
other than for the consolidated return group of which
NEES is the parent;
(xv) NERC has not participated, or cooperated
with, an international boycott within the meaning of
Section 999 of the Code; and
(xvi) NERC is not a party to any contract,
agreement or other arrangement which could result in
the payment of amounts that could be nondeductible by
reason of Sections 280G or 162(m) of the Code.
<PAGE>
5.21. NERC Holdings. NERC does not own fifty
percent or any greater percentage of the value of the
voting power of the capital stock of any other
corporation.
EXCEPT FOR THE REPRESENTATIONS AND WARRANTIES
EXPRESSLY SET FORTH IN THIS ARTICLE V, THE PURCHASED
ASSETS ARE BEING SOLD AND TRANSFERRED "AS IS, WHERE IS,"
AND THE SELLERS ARE NOT MAKING ANY OTHER REPRESENTATIONS
OR WARRANTIES, WRITTEN OR ORAL, STATUTORY, EXPRESS OR
IMPLIED, CONCERNING SUCH PURCHASED ASSETS, INCLUDING, IN
PARTICULAR, ANY WARRANTY OF MERCHANTABILITY OR FITNESS
FOR A PARTICULAR PURPOSE, ALL OF WHICH ARE HEREBY
EXPRESSLY EXCLUDED AND DISCLAIMED.
ARTICLE VI
REPRESENTATIONS AND WARRANTIES OF THE BUYER
The Buyer represents and warrants to the Sellers as
follows (all such representations and warranties, except
those regarding the Buyer, being made to the best
knowledge of the Buyer after reasonable inquiry or
investigation):
6.1. Organization. The Buyer is a corporation duly
organized, validly existing and in good standing under
the laws of the State of Delaware and has all requisite
corporate power and authority to own, lease and operate
its properties and to carry on its business as is now
being conducted. The Buyer has heretofore delivered to
the Sellers complete and correct copies of its
Certificate of Incorporation and By-laws (or other
similar governing documents), as currently in effect.
6.2. Authority Relative to this Agreement. The
Buyer has full corporate power and authority to execute
and deliver this Agreement and to consummate the
transactions contemplated hereby. The execution and
delivery of this Agreement and the consummation of the
transactions contemplated hereby have been duly and
validly authorized by the Board of Directors of the Buyer
and no other corporate proceedings on the part of the
Buyer are necessary to authorize this Agreement or to
<PAGE>
consummate the transactions contemplated hereby. This
Agreement has been duly and validly executed and
delivered by the Buyer, and assuming that this Agreement
constitutes a valid and binding agreement of the Sellers,
subject to the receipt of the Buyer Required Regulatory
Approvals and the Sellers Required Regulatory Approvals,
constitutes a valid and binding agreement of the Buyer,
enforceable against the Buyer in accordance with its
terms, except that such enforceability may be limited by
applicable bankruptcy, insolvency, moratorium or other
similar laws affecting or relating to enforcement of
creditors' rights generally or general principles of
equity.
6.3. Consents and Approvals; No Violation.
(a) Except as set forth in Schedule 6.3, and other
than obtaining the Buyer Required Regulatory Approvals
and the Sellers Required Regulatory Approvals, neither
the execution and delivery of this Agreement by the Buyer
nor the purchase by the Buyer of the Purchased Assets
pursuant to this Agreement will (i) conflict with or
result in any breach of any provision of the Certificate
of Incorporation or By-Laws (or other similar governing
documents) of the Buyer, (ii) require any consent,
approval, authorization or permit of, or filing with or
notification to, any governmental or regulatory
authority, (iii) result in a default (or give rise to any
right of termination, cancellation or acceleration) under
any of the terms, conditions or provisions of any note,
bond, mortgage, indenture, agreement, lease or other
instrument or obligation to which the Buyer or any of its
subsidiaries is a party or by which any of their
respective assets may be bound, except for such defaults
(or rights of termination, cancellation or acceleration)
as to which requisite waivers or consents have been
obtained.
(b) Except as set forth in Schedule 6.3 and except
for (i) qualification of the Buyer as an exempt wholesale
generator under the Energy Policy Act of 1992, without
restriction, including no restriction on sales to
Affiliates, (ii) authorization to sell power under
Section 205 of the FPA, including (A) authorizations
required to implement sales under the Ancillary
Agreements, and (B) market-based rate approval, (iii)
approval under Section 203 of the FPA to transfer
<PAGE>
contracts and other jurisdictional assets, (iv) approval
by FERC, under Part I of the FPA, of the transfer of FERC
project licenses related to, and necessary to operate,
the Hydroelectric Assets as currently operated, (v) any
state public utility approval necessary for the Sellers
to transfer any Purchased Assets in such state and for
the Buyer to purchase the Purchased Assets in any such
state, (vi) the filings by the Buyer and the Sellers
required by the HSR Act and (vii) approval of the
Continuing Site Agreement, the Transition Agreements and
the Wholesale Sales Agreement by FERC (the filings and
approvals referred to in clauses (i) through (vii) are
collectively referred to as the "Buyer Required
Regulatory Approvals"), no declaration, filing or
registration with, or notice to, or authorization,
consent or approval of any governmental or regulatory
body or authority is necessary for the consummation by
the Buyer of the transactions contemplated hereby.
6.4. Regulation as a Utility. The Buyer is not
subject to regulation as a public utility or public
service company (or similar designation other than as an
Exempt Wholesale Generator within the meaning of the
Holding Company Act) by the United States, any State of
the United States, any foreign country or any
municipality or any political subdivision of the
foregoing.
6.5. Availability of Funds. The Buyer has
sufficient funds available to it or has received binding
written commitments from responsible financial
institutions to provide sufficient funds on the Closing
Date to pay the Purchase Price.
ARTICLE VII
COVENANTS OF THE PARTIES
7.1. Conduct of Business Relating to the Purchased
Assets. (a) Except as described in Schedule 7.1, during
the period from the date of this Agreement to the Closing
Date, the Sellers will operate the Purchased Assets and
related businesses in the usual, regular and ordinary
course consistent with good industry practice and shall
use all commercially reasonable efforts to preserve
<PAGE>
intact the Purchased Assets and the businesses related
thereto, and endeavor to preserve the goodwill and
relationships with customers, suppliers and others having
business dealings with them. Without limiting the
generality of the foregoing, and, except as contemplated
in this Agreement or as described in Schedule 7.1, prior
to the Closing Date, without the prior written consent of
the Buyer, the Sellers will not with respect to the
Purchased Assets and related businesses:
(i) (x) except for (1) Permitted Encumbrances and
(2) indebtedness constituting Excluded Liabilities
that does not create an Encumbrance on the Purchased
Assets, create, incur, assume or suffer to exist any
indebtedness for borrowed money (including obligations
in respect of capital leases); or (y) assume,
guarantee, endorse or otherwise become directly liable
or responsible (whether directly or indirectly,
contingently or otherwise) for the obligations of any
Person;
(ii) make any material change in the levels of
fuel inventory and stores inventory customarily
maintained by the Sellers with respect to the
Purchased Assets, other than consistent with good
industry practice;
(iii) sell, lease (as lessor), transfer or
otherwise dispose of, any of the Purchased Assets,
other than assets used, consumed or replaced in the
ordinary course of business consistent with good
industry practice;
(iv) terminate, extend or otherwise amend any of
the Sellers' Agreements, the PPAs, any leases listed
in Schedule 5.9 or any other lease to the extent any
such extension or amendment would require the lease to
be disclosed on Schedule 5.9, or waive any default by,
or release, settle or compromise any claim against,
any other party thereto;
(v) enter into, terminate, extend or otherwise
amend any real or personal property Tax agreement,
treaty or settlement other than entering into any such
agreement, treaty or settlement with Hinsdale, NH,
<PAGE>
Lebanon, NH, and Monroe, NH; on substantially the same
terms as reflected in the drafts heretofore delivered
to the Buyer;
(vi) execute, enter into, terminate or otherwise
amend (x) any of the Permits, other than routine
renewals or non-material modifications or amendments,
(y) the MOA I or the MOA II or (z) any other
agreement, order, decree or judgment relating to the
current or any new NPDES permit for Brayton Point;
(vii) enter into any commitment for the purchase or
sale of fuel (whether commodity or transportation)
having a term that extends beyond March 31, 1998 or
such other date that the parties mutually agree to be
the date on which the Closing is expected to occur;
(viii) enter into any power purchase commitment,
having a term that extends beyond March 31, 1998 or
such other date that the parties mutually agree to be
the date on which the Closing is expected to occur;
(ix) enter into any power sales commitments having
a term that extends beyond March 31, 1998 or such
other date that the parties mutually agree to be the
date on which the Closing is expected to occur;
(x) [Intentionally omitted]
(xi) with respect to the Purchased Assets and
related businesses, (x) amend or cancel any liability
or casualty insurance policies related thereto, (y)
compromise, settle, withdraw, release or abate any
claims made or accruing thereunder or (z) fail to
maintain by self insurance or with financially
responsible insurance companies insurance in such
amounts and against such risks and losses as are
customary for such assets and businesses;
(xii) with respect to NERC, permit or cause NERC to
change its capital structure; amend its charter,
by-laws or other governing documents; issue new
securities; merge, consolidate or combine with any
other entity; hire any employees; purchase or sell any
assets; create or suffer to exist; any liabilities,
<PAGE>
contingent or otherwise, not directly attributable to
its general partnership interests in OSP and OSP II;
or change its business as presently conducted;
(xiii) enter into any commitment or contract for
goods or services not addressed in clauses (i) through
(xii) above that will be delivered or provided after
March 31, 1998 or such other date that the parties
mutually agree to be the date on which the Closing is
expected to occur, in an amount greater than
$1,000,000;
(xiv) enter into any written or oral contract,
agreement, commitment or arrangement with respect to
any of the transactions set forth in the foregoing
paragraphs (i) through (xiii).
(b) Notwithstanding anything in Section 7.1(a) to
the contrary, the Sellers may, in their sole discretion,
make (i) Maintenance Expenditures and Capital
Expenditures, (ii) at the Sellers' expense, such other
maintenance and capital expenditures as the Sellers deem
necessary and (iii) enter into the settlement agreement
with regard to the Fifteen Mile Falls Project,
substantially in the form heretofore delivered to the
Buyer.
(c) A committee comprised of one Person designated
by the Sellers and one Person designated by the Buyer,
and such additional Persons as may be appointed by the
Persons originally appointed to such committee (the
"Transition Committee") will be established as soon after
execution of this Agreement as is practicable to examine
the business issues affecting the Purchased Assets and
related businesses of the Sellers after the date hereof,
giving emphasis to cooperation between the Buyer and the
Sellers after the execution of this Agreement. From time
to time, the Transition Committee shall report its
findings to the senior management of each of NEP and the
Buyer.
(d) Between the date of this Agreement and the
Closing Date, in the interest of cooperation between the
Sellers and the Buyer and to permit informed action by
the Buyer regarding its rights pursuant to Section 7.1(a)
to grant, consent or to waive prohibitions or limitations
under Section 7.1(a), the parties agree as follows:
<PAGE>
(i) At the sole responsibility and expense of the
Buyer, the Sellers will permit designated employees
("Observers") of the Buyer to observe all operations
of the Sellers that relate to the Purchased Assets and
related businesses, and such observation will be
permitted on a cooperative basis in the presence of
personnel of the Sellers but not restricted to the
normal business hours of the Sellers; provided,
however, that such observers and their actions shall
not unreasonably interfere with the operation of the
Sellers business. The Buyer's Observers may recommend
or suggest actions be taken or not be taken by the
Sellers; provided, however, that the Sellers will be
under no obligation to follow any such recommendations
or suggestions and the Sellers shall be entitled,
subject to this Agreement, to conduct their business
in accordance with their own judgment and discretion.
The Buyer's Observers shall have no authority to bind
or make agreements on behalf of the Sellers; to
conduct discussions with or make representations to
third parties on behalf of the Sellers; or to issue
instructions to or direct or exercise authority over
the Sellers or any of the Seller's officers,
employees, advisors or agents.
(ii) For certain specific issues, such as the
Brayton Point NPDES permit negotiations and planning,
the Sellers may assign Observers to the Sellers' teams
working on these specific issues.
(iii) The Buyer shall have the right, to the extent
that it can demonstrate to NEP a legitimate business
purpose, to direct that NEP enter into contracts and
commitments that exceed the limitations imposed by
Sections 7.1(a)(ii) and (vii); provided, however, that
in such event the Buyer will assume for its own
account any obligations and liabilities associated
therewith, all of which shall constitute Assumed
Obligations for purposes of this Agreement; provided,
however, that NEP shall not be required to enter into
such contracts and commitments unless the Buyer has
provided NEP with a reasonable mechanism to hold NEP
harmless for any liabilities incurred in connection
with such contracts and commitments.
<PAGE>
(e) The Buyer and Sellers each agree to consult
with each other regarding matters involving the governing
arrangements or procedures of the New England Power Pool.
The Sellers shall take the Buyer's views on such matters
into account, with particular deference to matters
involving predominately the generation business, prior to
exercising Sellers' rights and obligations with respect
to the New England Power Pool.
7.2. Access to Information. (a) Between the date
of this Agreement and the Closing Date, the Sellers will,
during ordinary business hours and upon reasonable notice
(i) give the Buyer and the Buyer Representatives
reasonable access to all books, records, plants, offices
and other facilities and properties constituting the
Purchased Assets to which the Buyer is not denied access
by law; (ii) permit the Buyer to make such reasonable
inspections thereof as the Buyer may reasonably request;
(iii) furnish the Buyer with such financial and operating
data and other information with respect to the Purchased
Assets as the Buyer may from time to time reasonably
request; (iv) furnish the Buyer a copy of each material
report, schedule or other document filed or received by
them with respect to the Purchased Assets with the SEC,
MDPU, RIPUC, NHPUC, VTPSB, NRC or FERC; provided,
however, that (A) any such investigation shall be
conducted in such a manner as not to interfere
unreasonably with the operation of the Purchased Assets,
(B) the Sellers shall not be required to take any action
which would constitute a waiver of the attorney-client
privilege and (C) the Sellers need not supply the Buyer
with any information which the Sellers are under a legal
obligation not to supply. Notwithstanding anything in
this Section 7.2 to the contrary, (i) the Sellers will
only furnish or provide such access to Transferring
Employee Records and personnel and medical records as is
required by law, legal process or subpoena and (ii) the
Buyer shall not have the right to perform or conduct any
environmental sampling or testing at, in, on, or
underneath the Purchased Assets.
(b) The Buyer and Sellers acknowledge that Buyer
is a Representative of U.S. Generating Company under the
terms of the Confidentiality Agreement. All information
furnished to or obtained by the Buyer, U.S. Generating
<PAGE>
Company and the Buyer Representatives pursuant to this
Section 7.2 shall be subject to the provisions of the
Confidentiality Agreement and shall be treated as
"Proprietary Information" (as defined in the
Confidentiality Agreement).
(c) For a period of ten years after the Closing
Date, each party and their representatives shall have
reasonable access to all of the books and records of the
Purchased Assets, including all Transferring Employee
Records or other personnel and medical records required
by law, legal process or subpoena, in the possession of
the other party or parties to the extent that such access
may reasonably be required by such party in connection
with the Assumed Obligations or the Excluded Liabilities,
or other matters relating to or affected by the operation
of the Purchased Assets. Such access shall be afforded
by the party or parties in possession of such books and
records upon receipt of reasonable advance notice and
during normal business hours. The party or parties
exercising this right of access shall be solely
responsible for any costs or expenses incurred by it or
them pursuant to this Section 7.2(c). If the party or
parties in possession of such books and records shall
desire to dispose of any such books and records upon or
prior to the expiration of such ten-year period, such
party or parties shall, prior to such disposition, give
the other party or parties a reasonable opportunity at
such other party's or parties' expense, to segregate and
remove such books and records as such other party or
parties may select.
(d) The Sellers agree to use best efforts to cause
NEES not to release any Person (other than the Buyer)
from any confidentiality agreement now existing with
respect to the Purchased Assets, or waive or amend any
provision thereof.
(e) Notwithstanding the terms of the
Confidentiality Agreement and Section 7.2(b) above, the
parties agree that prior to the Closing the Buyer may
reveal or disclose Proprietary Information to any other
Persons in connection with financing, and risk management
if reasonably necessary, of or with respect to the
Purchased Assets, and to such Persons with whom the Buyer
expects it may have business dealings regarding the
<PAGE>
Purchased Assets from and after the Closing Date, and, to
the extent that Sellers consent, which consent shall not
be unreasonably withheld, existing and potential
customers and suppliers. The parties further agree that
clause (c) of the first sentence of the second paragraph
of the Confidentiality Agreement is terminated, and of no
further force or effect.
(f) Except as required by law, unless otherwise
agreed to in writing by the Buyer, for a period
commencing on the Closing Date and terminating three
years after such date the Sellers shall keep (i) all
Proprietary Information confidential and not disclose or
reveal any Proprietary Information to any Person other
than "Sellers' Representatives" (as defined below) who
are actively and directly participating in the
transactions contemplated hereby or who otherwise need to
know the Proprietary Information for such purpose and to
cause those Persons to observe the terms of this Section
7.2(f) and (ii) not to use Proprietary Information for
any purpose other than consistent with the terms of this
Agreement. The Sellers shall continue to hold all
Proprietary Information according to the same internal
security procedures and with the same degree of care
regarding its secrecy and confidentiality as currently
applicable thereto. The Sellers shall notify the Buyer
of any unauthorized disclosure to third parties that it
discovers, and shall endeavor to prevent any further such
disclosures. The Sellers shall be responsible for any
breach of the terms of this Section 7.2(f) by the Sellers
or the Sellers' Representatives.
After the Closing Date, in the event that the
Sellers are requested pursuant to, or required by,
applicable law or regulation or by legal process to
disclose any Proprietary Information, or any other
information concerning the Purchased Assets, or the
transactions contemplated hereby, the Sellers shall
provide the Buyer with prompt notice of such request or
requirement in order to enable the Buyer to seek an
appropriate protective order or other remedy, to consult
with the Sellers with respect to taking steps to resist
or narrow the scope of such request or legal process, or
to waive compliance, in whole or in part, with the terms
of this Section 7.2(f). The Sellers agree not to oppose
any action by the Buyer to obtain a protective order or
<PAGE>
other appropriate remedy after the Closing Date. In the
event that no such protective order or other remedy is
obtained, or that the Buyer waives compliance with the
terms of this Section 7.2(f), the Sellers shall furnish
only that portion of the Proprietary Information which
the Sellers are advised by counsel is legally required.
In any such event the Sellers shall use their reasonable
best efforts to ensure that all Proprietary Information
and other information that is so disclosed will be
accorded confidential treatment.
(g) The parties agree that the last sentence of
the third paragraph of the Confidentiality Agreement
shall not apply with respect to Proprietary Information
that is included in the Purchased Assets.
(h) The parties agree that the Confidentiality
Agreement will terminate, without further act or evidence
by the parties, upon consummation of the Closing.
(i) The Sellers shall use best efforts to cause
NEES to execute appropriate written evidence of its
agreement to the terms of this Section 7.2 insofar as the
Confidentiality Agreement is amended or superseded
hereby.
7.3. Expenses. Except to the extent specifically
provided herein, whether or not the transactions
contemplated hereby are consummated, all costs and
expenses incurred in connection with this Agreement and
the transactions contemplated hereby shall be borne by
the party incurring such costs and expenses.
7.4. Further Assurances. (a) Subject to the terms
and conditions of this Agreement, each of the parties
hereto will use its best efforts to take, or cause to be
taken, all action, and to do, or cause to be done, all
things necessary, proper or advisable under applicable
laws and regulations to consummate and make effective the
sale of the Purchased Assets pursuant to this Agreement,
including without limitation using its best efforts to
ensure satisfaction of the conditions precedent to each
party's obligations hereunder. Notwithstanding anything
in the previous sentence to the contrary, the Sellers and
the Buyer shall use their commercially reasonable efforts
to obtain all Permits and Environmental Permits necessary
<PAGE>
for the Buyer to operate the Purchased Assets. Neither
of the parties hereto will, without prior written consent
of the other party, take or fail to take any action,
which would reasonably be expected to prevent or
materially impede, interfere with or delay the
transactions contemplated by this Agreement. From time
to time after the date hereof, without further
consideration, the Sellers will, at their own expense,
execute and deliver such documents to the Buyer as the
Buyer may reasonably request in order to more effectively
vest in the Buyer the Sellers' title to the Purchased
Assets subject to Permitted Encumbrances and Schedule
5.8. Without limiting the foregoing, the Sellers shall
cooperate with the Buyer in the Buyer's efforts to cure
or remove any defects or Encumbrances existing with
respect to the Real Estate that the Buyer reasonably
deems objectionable; provided, however, that in
connection therewith the Sellers shall not be under any
obligation to initiate legal action or to incur expense
other than reasonable administrative and out-of-pocket
expenses. From time to time after the date hereof, the
Buyer will, at its own expense, execute and deliver such
documents to the Sellers as the Sellers may reasonably
request in order to more effectively consummate the sale
of the Purchased Assets pursuant to this Agreement.
(b) In the event that any Purchased Asset shall
not have been conveyed to the Buyer at the Closing, the
Sellers shall, subject to Section 7.4(c), the PPA
Transfer Agreement and the PSA Performance Support
Agreements, use their best efforts to convey such asset
to the Buyer as promptly as is practicable after the
Closing. In the event that any Easement shall not have
been retained by the Sellers after the Closing, the Buyer
shall use its best efforts to grant such Easement to the
Sellers as promptly as is practicable after the Closing.
(c) Subject to the PPA Transfer Agreement and the
PSA Performance Support Agreements, to the extent that
the Sellers' rights under any Sellers' Agreement may not
be assigned without the consent of another Person which
consent has not been obtained, this Agreement shall not
constitute an agreement to assign the same if an
attempted assignment would constitute a breach thereof or
be unlawful, and the Sellers, at their expense, shall use
their commercially reasonable efforts to obtain any such
<PAGE>
required consent(s) as promptly as possible. The Sellers
and the Buyer agree that if any consent to an assignment
of any Sellers' Agreement shall not be obtained or if any
attempted assignment would be ineffective or would impair
the Buyer's rights and obligations under the Sellers'
Agreement in question so that the Buyer would not in
effect acquire the benefit of all such rights and
obligations, the Sellers, to the maximum extent permitted
by law and such Sellers' Agreement, shall after the
Closing, unless the Sellers elect to comply with Section
7.4(e) hereof, appoint the Buyer to be the Sellers'
representative and agent with respect to such Sellers'
Agreement, and the Sellers shall, to the maximum extent
permitted by law and such Sellers' Agreement, enter into
such reasonable arrangements with the Buyer as are
necessary to provide the Buyer with the benefits and
obligations of such Sellers' Agreement. The Sellers and
the Buyer shall cooperate and shall each use their
commercially reasonable efforts after the Closing to
obtain an assignment of such Sellers' Agreement to the
Buyer.
(d) Sellers and Buyer covenant and agree to
negotiate and enter into in good faith such further
agreements for operating the Purchased Assets, after the
Closing Date, including those agreements described on
Schedule 7.4(d).
(e) To the extent that any personal property
lease, relating to any assets which are principally used
by the Sellers for generation purposes at the Purchased
Assets, cannot be assigned to the Buyer or are not
subject to arrangements described in Section 7.4(c), the
Sellers will use their commercially reasonable efforts to
acquire the assets relating to such lease and to include
them in the Purchased Assets before the Closing Date.
7.5. Public Statements. The parties shall consult
with each other prior to issuing any public announcement,
statement or other disclosure with respect to this
Agreement or the transactions contemplated hereby and
shall not issue any such public announcement, statement
or other disclosure prior to such consultation, except as
may be required by law and except that the parties may
make public announcements, statements or other
disclosures with respect to this Agreement and the
<PAGE>
transactions contemplated hereby to the extent and under
the circumstances in which the parties are expressly
permitted by the Confidentiality Agreement to make
disclosures of "Proprietary Information" (as defined in
the Confidentiality Agreement).
7.6. Consents and Approvals. (a) The Sellers and
the Buyer shall each file or cause to be filed with the
Federal Trade Commission and the United States Department
of Justice any notifications required to be filed under
the HSR Act and the rules and regulations promulgated
thereunder with respect to the transactions contemplated
hereby. The parties shall consult with each other as to
the appropriate time of filing such notifications and
shall use their best efforts to make such filings at the
agreed upon time, to respond promptly to any requests for
additional information made by either of such agencies,
and to cause the waiting periods under the HSR Act to
terminate or expire at the earliest possible date after
the date of filing.
(b) The Sellers and the Buyer shall cooperate with
each other and (i) promptly prepare and file all
necessary documentation, (ii) effect all necessary
applications, notices, petitions and filings and execute
all agreements and documents, (iii) use all commercially
reasonable efforts to obtain the transfer or reissuance
to the Buyer of all necessary Transferable Permits,
consents, approvals and authorizations of all
governmental bodies and (iv) use all commercially
reasonable efforts to obtain all necessary consents,
approvals and authorizations of all other parties, in the
case of each of the foregoing clauses (i), (ii), (iii)
and (iv), necessary or advisable to consummate the
transactions contemplated by this Agreement (including,
without limitation, the Sellers Required Regulatory
Approvals and the Buyer Required Regulatory Approvals) or
required by the terms of any note, bond, mortgage,
indenture, deed of trust, license, franchise, permit,
concession, contract, lease or other instrument to which
the Sellers or the Buyer is a party or by which any of
them is bound. Each of the Sellers and the Buyer shall
have the right to review in advance all characterizations
of the information relating to the transactions
contemplated by this Agreement which appear in any filing
made in connection with the transactions contemplated
hereby.
<PAGE>
(c) The Sellers and the Buyer shall cooperate with
each other and promptly prepare and file notifications
with, and request Tax clearances from, state and local
taxing authorities in jurisdictions in which a portion of
the Purchase Price may be required to be withheld or in
which the Buyer would otherwise be liable for any Tax
liabilities of the Sellers pursuant to such state and
local Tax law.
7.7. Fees and Commissions. The Sellers and the
Buyer each represent and warrant to the other that,
except for Merrill Lynch & Co., which is acting for and
at the expense of the Sellers, and Barr Devlin Associates
Incorporated and Societe Generale, which are acting for
and at the expense of the Buyer, no broker, finder or
other Person is entitled to any brokerage fees,
commissions or finder's fees in connection with the
transaction contemplated hereby by reason of any action
taken by the party making such representation. The
Sellers and the Buyer will pay to the other or otherwise
discharge, and will indemnify and hold the other harmless
from and against, any and all claims or liabilities for
all brokerage fees, commissions and finder's fees (other
than the fees, commissions and finder's fees payable to
the parties listed above) incurred by reason of any
action taken by such party.
7.8. Tax Matters. (a) All transfer and sales taxes
incurred in connection with this Agreement and the
transactions contemplated hereby shall be borne by the
Buyer, and the Buyer, at its own expense, will file, to
the extent required by applicable law, all necessary Tax
Returns and other documentation with respect to all such
transfer or sales taxes, and, if required by applicable
law, the Sellers will join in the execution of any such
Tax Returns or other documentation. Prior to the Closing
Date, the Buyer will provide to the Sellers, to the
extent possible, an appropriate certificate of no Tax
incurred in connection with this Agreement and the
transactions contemplated hereby, due from each
applicable taxing authority.
(b) With respect to Taxes to be prorated in
accordance with Section 3.5 of this Agreement only, the
Buyer shall prepare and timely file all Tax Returns
<PAGE>
required to be filed after the Closing with respect to
the Purchased Assets, if any, and shall duly and timely
pay all such Taxes shown to be due on such Tax Returns.
The Buyer's preparation of any such Tax Returns shall be
subject to the Sellers' approval, which approval shall
not be unreasonably withheld. The Buyer shall make such
Tax Returns available for the Sellers' review and
approval no later than fifteen (15) Business Days prior
to the due date for filing such Tax Return. Within ten
(10) Business Days after receipt of such Tax Return, the
Sellers shall pay to the Buyer their proportionate share
of the amount shown as due on such Tax Return determined
in accordance with Section 3.5 of this Agreement.
(c) Each of the Buyer and the Sellers shall
provide the other with such assistance as may reasonably
be requested by the other party in connection with the
preparation of any Tax Return, any audit or other
examination by any taxing authority, or any judicial or
administrative proceedings relating to liability for
Taxes, and each will retain and provide the requesting
party with any records or information which may be
relevant to such return, audit or examination,
proceedings or determination. Any information obtained
pursuant to this Section 7.8(c) or pursuant to any other
Section hereof providing for the sharing of information
or review of any Tax Return or other schedule relating to
Taxes shall be kept confidential by the parties hereto.
(d) NERC Tax Matters.
(1) Section 338(h)(10) Election. (i) With respect
to the sale of the NERC Stock, the Sellers and the
Buyer shall jointly make the election provided for by
Section 338(h)(10) of the Code and Section
1.338(h)(10)-1 of the Treasury Regulations promulgated
under the Code and any comparable election under state
or local tax law (the "Election"). As soon as
practicable after the Closing Date, with respect to
such Election, the Sellers and the Buyer shall
mutually prepare a Form 8023-A, with all attachments,
and the Sellers shall sign such Form 8023-A. The
Buyer and the Sellers shall also cooperate with each
other to take all actions necessary and appropriate
(including filing such additional forms, returns,
elections, schedules and other documents as may be
<PAGE>
required) to effect and preserve such Election in
accordance with the provisions of Section 1.338(h)(10)-
1 of the Treasury Regulations (or any comparable
provisions of state and local tax law) or any
successor provisions.
(ii) With respect to the Election the Modified
Aggregate Deemed Sales Price as defined in Section
1.338(h)(10)-1 of the Treasury Regulations (the
"Modified ADSP") shall be allocated among the assets
of NERC pursuant to Treasury Regulation Section
1.338(h)(10)-1. The Buyer and the Sellers shall use
their good faith best efforts to agree upon such
allocation. The Sellers shall provide to the Buyer a
schedule and supporting material reflecting such
allocation for the Buyer's review and consent, such
consent not to be unreasonably withheld. The parties
shall take no action inconsistent with, or fail to
take any action necessary for the validity of, the
Election, and shall adopt and utilize the asset values
determined from such reasonable allocation for the
purpose of all Tax Returns filed by them, and shall
not voluntarily take any action inconsistent therewith
upon examination of any Tax Return, in any refund
claim, in any litigation or otherwise with respect to
such Tax Returns.
(2) Return Filing, Payments, Refunds and Credits.
Notwithstanding anything to the contrary in Section
3.5 of this Agreement,
(i) For purposes of this Agreement, (a) the
amount of Taxes of NERC attributable to the pre-
Closing portion of any taxable period beginning before
and ending after the Closing Date (the "Straddle
Period") shall be determined based upon the cumulative
monthly income statements of NERC for all months
ending prior to the Closing Date and upon the relative
number of days in the pre-Closing and post-Closing
portion of the month in which the Closing Date occurs,
(b) taxable income attributable to NERC's interests in
OSP and OSP II shall be determined by reference to the
relative number of days in the pre-Closing and post-
Closing portions of such Straddle Period; provided,
however, that Taxes imposed on a periodic basis shall
be determined by reference to the relative number of
<PAGE>
days in the pre-Closing and post-Closing portions of
such Straddle Period and any extraordinary transaction
shall be allocated to the portion of such Straddle
Period in which it occurred.
(ii) The Buyer and the Sellers shall cause NERC to
join, for all pre-Closing periods and the Straddle
Period for which NERC is required or eligible to do
so, in all consolidated, combined or unitary federal,
state, or local Income Tax or franchise Tax Returns of
the Sellers (or any Tax Affiliate for all pre-Closing
periods ("Sellers' Tax Returns")), and shall, in each
jurisdiction where this is required or permissible
under applicable law, cause the taxable year of NERC
to terminate as of the Closing Date. The Sellers
shall cause to be prepared and timely filed all such
Sellers' Tax Returns and shall cause to be paid all
Taxes shown to be due on such Sellers' Tax Returns;
provided, however, that in the case of a Sellers' Tax
Return for the Straddle Period, the Buyer shall or
shall cause NERC to pay to the Sellers the portion of
such Taxes shown to be due thereon attributable to
NERC for the post-Closing Date portion of the Straddle
Period determined in accordance with Section
7.8(d)(2)(i) and the NEES Intercompany Tax Allocation
Agreement in effect on the date of the signing of this
Agreement (the "NEES Intercompany Tax Allocation
Agreement").
(iii) The Buyer shall or shall cause NERC to
prepare and timely file all Income Tax Returns of NERC
for all pre-Closing periods and the Straddle Period,
other than those referred to in Section 7.8(d)(2)(ii),
which Income Tax Returns have not been filed as of the
Closing Date, and shall cause to be timely paid all
Taxes shown to be due on such Tax Returns. No later
than ten days prior to the due date for the filing of
each Income Tax Return referred to in this Section
7.8(d)(2)(iii), the Sellers shall pay to NERC the
amount of Taxes shown as due thereon less any
estimated Taxes paid by NERC during the pre-Closing
period; provided, however, that in the case of an
Income Tax Return for a Straddle Period, the Sellers
shall only be required to pay NERC the portion of such
Taxes that is attributable to the pre-Closing Date
portion of such Straddle Period, determined in
<PAGE>
accordance with Section 7.8(d)(2)(i) and the NEES
Intercompany Tax Allocation Agreement less any
estimated Taxes paid by NERC during the pre-Closing
period. The Sellers shall fully cooperate with the
Buyer and NERC in accordance with past practice in the
preparation of the Income Tax Returns referred to in
this Section 7.8(d)(2)(iii).
(iv) The Buyer shall or shall cause NERC to
prepare and timely file all Tax Returns of NERC for
all pre-Closing periods and the Straddle Period, other
than those Tax Returns referred to in Section
7.8(d)(2)(ii) and (iii), which Tax Returns have not
been filed as of the Closing Date, and shall cause to
be timely paid all Taxes shown to be due thereon. No
later than ten days prior to the due date for the
filing of each Tax Return referred to in this Section
7.8(d)(2)(iv), the Sellers shall pay to NERC the
amount shown as due thereon attributable to the pre-
Closing Date portion of the Straddle Period less any
estimated Taxes paid by NERC during the pre-Closing
period.
(v) The Tax Returns referred to in Section
7.8(d)(2)(ii), (iii) and (iv) shall be prepared in a
manner consistent with past practice, unless a
contrary treatment is required by an intervening
change in the applicable law. Except for calendar
year 1996 Tax Returns, the Sellers shall cause to be
made available to Buyer a copy of any Tax Return that
is required to be filed by the Sellers or NERC under
7.8(d)(2)(ii) and the Buyer shall cause to be made
available to the Sellers a copy of any Tax Return that
is required to be filed by the Buyer or NERC under
Section 7.8(d)(2)(iii) or (iv), in each case together
with all relevant workpapers and other information.
Each such Tax Return shall be made available for
review and approval no later than 20 Business Days
prior to the due date for the filing of such Tax
Return (taking into account proper extensions), such
approval not to be unreasonably withheld. An exact
copy of any such Tax Return filed by the Buyer shall
be provided to the Sellers and any such Tax Return
filed by the Sellers shall be provided to the Buyer,
in each case, no later than ten days after such Tax
Return is filed.
<PAGE>
(vi) Any refunds or credits of the Taxes of NERC
plus any interest received with respect thereto from
the applicable taxing authorities for any Closing
period (including without limitation, refunds or
credits arising from amended returns filed after the
Closing Date) shall be for the account of the Sellers,
except to the extent that such refunds or credits are
attributable to the mandatory carryback of any
deductions or credits for any Tax Period ending after
a Closing Date and, if received by the Buyer or NERC,
shall be paid to the Sellers within ten days after the
Buyer or NERC receives such refund or after the
relevant Tax Return is filed within which the credit
is applied against the Buyer's or NERC's liability for
Taxes for a period which begins after the Closing
Date, net of any Taxes the Buyer or NERC is required
to pay on account of receiving such refund or credit
(including a reasonable estimate of resulting future
Tax costs.) The Sellers, without the consent of the
Buyer, shall not apply for any refund that will create
a material adverse effect on any post-Closing period
Tax Return and shall not apply for any refund for any
Straddle Period Tax Return or any Tax Return for NERC
that is not a consolidated, combined, or unitary Tax
Return. Any refunds or credits of Taxes of NERC for
any Straddle Period shall be apportioned between the
Sellers and the Buyer in the same manner as the
liability for such Taxes is apportioned pursuant to
Section 7.8(d)(2)(i).
(3) Tax Indemnification. (i) Without duplication,
the Sellers shall indemnify, defend and hold the Buyer
harmless from and against any and all Taxes (including
interest and penalties) which may be suffered or
incurred by them in respect of or relating to,
directly or indirectly (x) Taxes of or attributable to
NERC for all pre-Closing periods, (y) Taxes of or
attributable to NERC with respect to the pre-Closing
portion of the Straddle Period, and (z) Taxes payable
by NERC with respect to any pre-Closing period or
Straddle Period by reason of NERC being severally
liable for the Tax of any Tax Affiliate pursuant to
Treasury Regulation Section 1.1502-6 or any analogous
state or local Tax law.
<PAGE>
(ii) Without duplication, the Buyer shall
indemnify, defend and hold the Sellers harmless from
and against any and all Taxes (including interest and
penalties) which may be suffered or incurred by them
in respect of or relating to, directly or indirectly
(x) Taxes of or attributable to NERC with respect to
all post-Closing periods, (y) Taxes of or attributable
to NERC with respect to the post-Closing portion of
any Straddle Period.
(4) Tax Contest. (i) Each of the Sellers and the
Buyer shall notify the other party in writing within
30 days of receipt of written notice of any pending or
threatened tax examination, audit or other
administrative or judicial proceeding (a "Tax
Contest") that could reasonably be expected to result
in an indemnification obligation under this Section
7.8(d) of such other party pursuant to this Section
7.8(d). If the recipient of such notice of a Tax
Contest fails to provide such notice to the other
party, it shall not be entitled to indemnification for
any Taxes arising in connection with such Tax Contest,
but only to the extent, if any, that such failure or
delay shall have adversely affected the indemnifying
party's ability to defend against, settle, or satisfy
any action, suit or proceeding against it, or any
damage, loss, claim, or demand for which the
indemnified party is entitled to indemnification
hereunder.
(ii) If a Tax Contest relates to any period ending
on or prior to the Closing Date or to any Taxes for
which the Sellers are liable in full hereunder, the
Sellers shall at their expense control the defense and
settlement of such Tax Contest. If such Tax Contest
relates to any period beginning after the Closing Date
or to any Taxes for which the Buyer is liable in full
hereunder, the Buyer shall at its own expense control
the defense and settlement of such Tax Contest. The
party not in control of the defense shall have the
right to observe the conduct of any Tax Contest at its
expense, including through its own counsel and other
professional experts. The Buyer and the Sellers shall
jointly represent NERC in any Tax Contest relating to
<PAGE>
a Straddle Period, and fees and expenses related to
such representation shall be paid equally by the Buyer
and the Sellers.
(iii) Notwithstanding anything to the contrary in
Section 7.8(d)(4)(ii), to the extent that an issue
raised in any Tax Contest controlled by one party or
jointly controlled could materially affect the
liability for Taxes of the other party, the
controlling party shall not, and neither party in the
case of joint control shall, enter into a final
settlement without the consent of the other party,
which consent shall not be unreasonably withheld.
Where a party withholds its consent to any final
settlement, that party may continue or initiate
further proceedings, at its own expense, and the
liability of the party that wished to settle (as
between the consenting and the non-consenting party)
shall not exceed the liability that would have
resulted from the proposed final settlement (including
interest, additions to Tax, and penalties that have
accrued at that time), and the non-consenting party
shall indemnify the consenting party for such Taxes.
(5) Tax Sharing Agreements. Any Tax sharing
agreement to which NERC is a party shall be deemed
terminated with respect to NERC on, and effective as of,
the Closing Date, and no Person shall have any rights or
obligations under such Tax sharing agreement with respect
to NERC after such termination; provided, however, that
the NEES Intercompany Tax Allocation Agreement shall
remain in effect with respect to NERC in order to
determine the portion of the Sellers' Tax liabilities
attributable to NERC, and to be paid to the Sellers under
Section 7.8(d)(2)(ii) for the post-Closing Date portion
of the Straddle Period.
(e) Disputes. In the event that a dispute arises
between the Sellers and the Buyer as to the amount of
Taxes, or indemnification, whether or not attributable to
NERC, or the amount of any allocation of Purchase Price
under Sections 3.3(a) or 7.8(d)(1)(ii) hereof, the
parties shall attempt in good faith to resolve such
dispute, and any agreed upon amount shall be paid to the
appropriate party. If such dispute is not resolved 30
days thereafter, the parties shall submit the dispute to
<PAGE>
the Independent Accounting Firm for resolution, which
resolution shall be final, conclusive and binding on the
parties. Notwithstanding anything in this Agreement to
the contrary, the fees and expenses of the Independent
Accounting Firm in resolving the dispute shall be borne
equally by the Sellers and the Buyer. Any payment
required to be made as a result of the resolution of the
dispute by the Independent Accounting Firm shall be made
within ten days after such resolution, together with any
interest determined by the Independent Accounting Firm to
be appropriate.
(f) Sellers will reimburse Buyer for a percentage
of payments with respect to liabilities for real or
personal property Taxes under agreements entered into by
the Sellers and local governments, as set forth in
Schedule 7.8(f) hereof, within 30 days following delivery
to Sellers of evidence of such payments. With respect to
real or personal property Taxes payable in jurisdictions
in which no Tax Agreements are operative and in which
both Buyer and Sellers have property which is or is
potentially subject to property Tax, Buyer and Sellers
will cooperate in the filing of property Tax Returns with
the objective of maximizing Tax and administrative
efficiency to the benefit of both parties.
7.9. Supplements to Schedules. Prior to the
Closing Date, the Sellers and the Buyer shall supplement
or amend the Schedules required by Section 2.4, Article V
and Article VI, as the case may be, with respect to any
matter relating to the Purchased Assets, hereafter
arising which, if existing or occurring at the date of
this Agreement, would have been required to be set forth
or described in such Schedules. No supplement or
amendment of any Schedule made pursuant to this Section
shall be deemed to cure any breach of any representation
or warranty made in this Agreement unless the parties
agree thereto in writing.
7.10. Employees. (a) The Buyer may offer employment,
effective as of the Closing Date, to those employees of
the Sellers and their Affiliates whose employment
responsibilities primarily relate to the Fossil Assets
(including employees in the Fuel Services and Risk
management department and employees in the Construction
Services department) (all such employees
<PAGE>
hereinafter referred to as "Fossil Employees"), to any
other employees of the Sellers and their Affiliates who
are in a function listed in Schedule 7.10(a) or to any
other employees of the Sellers and their Affiliates whose
employment responsibilities relate to the Fossil Assets.
The Buyer may offer employment, effective as of the
Closing Date, to those employees of the Sellers and their
Affiliates whose employment responsibilities primarily
relate to the Hydroelectric Assets, hereinafter referred
to as "Hydroelectric Employees," to any remaining
employees of the Sellers and their Affiliates who are in
a function listed on Schedule 7.10(a) or to any other
remaining employees whose employment responsibilities
relate to the Purchased Assets.
All such offers of employment shall be made (i) in
accordance with all applicable laws and regulations, and
(ii)(x) for employees represented by Local Nos. 326 and
486 of the International Brotherhood of Electrical
Workers ("IBEW") and Local No. 464 of the Utility Workers
Union of America ("UWUA"), in accordance with the Main
Table Agreements and the IBEW/UWUA MOU, as defined in
Section 7.10(b) below, and (y) for employees represented
by Local Nos. 310 and 345 of the Brotherhood of Utility
Workers of New England, Incorporated ("BUW") in
accordance with the BUW MOU, as defined in Section
7.10(c) below. Each person who becomes employed by the
Buyer pursuant to this Section 7.10 shall be referred to
herein as a "NEPGen Employee."
The Sellers or any Affiliate of the Sellers may at
any time prior to the Closing Date, offer employment to
any Fossil Employees, Hydroelectric Employees, or any
other employees who are in a function listed on Schedule
7.10(a), as long as such employees are not participants
in the New England Electric Companies' Incentive
Compensation Plans I, II, or III (collectively, the
"Plans"). Without the prior consent of the Buyer, the
Sellers will refrain, and will use their best efforts to
cause their Affiliates to refrain, from offering
employment from the date of this Agreement until February
28, 1998 (the "Buyer Window") to Fossil Employees,
Hydroelectric Employees and any other employees whose
functions are listed on Schedule 7.10(a) who are
participants in the Plans. Thereafter, the Sellers or
any Affiliates of the Sellers may offer employment to
<PAGE>
said employees who did not accept a position with the
Buyer within the Buyer Window. Buyer may commence
offering employment to said employees 60 days after the
date of this Agreement. For all other employees Seller
and Buyer shall mutually agree upon the hiring process,
transition and timing thereof.
(b) Schedule 7.10(b) sets forth the collective
bargaining agreements, and amendments thereto, to which
the Sellers are a party with the IBEW and the UWUA in
connection with the Purchased Assets (the "Main Table
Agreements"), and the Memorandum of Understanding between
the Sellers and certain of their Affiliates and the IBEW
and the UWUA ("IBEW/UWUA MOU"). With respect to NEPGen
Employees who are included in the collective bargaining
units covered by the Main Table Agreements ("IBEW/UWUA
Employees"), on the Closing Date, the Buyer will assume
the Main Table Agreements as they relate to IBEW/UWUA
Employees to be employed at the Fossil Assets and comply
with all applicable obligations thereunder and will
accept and fulfill all obligations under the IBEW/UWUA
MOU that are designated for the new owner, including but
not limited to the obligation of the new owner to
recognize the respective union as the collective
bargaining agent. On the Closing Date, the Buyer will
assume the applicable Main Table Agreements as they
relate to IBEW/UWUA Employees to be employed at the
Hydroelectric Assets and comply with all applicable
obligations thereunder and will accept and fulfill all
obligations under the IBEW/UWUA MOU that are designated
for the new owner, including but not limited to the
obligation of the new owner to recognize the respective
union as the collective bargaining agent.
The Sellers and certain of their Affiliates have
established local working conditions with the IBEW/UWUA
at each facility which are comprised of local agreements,
copies of which the Buyer hereby acknowledges that it has
had the opportunity to review, and local past practices
("Local Working Conditions"). Pursuant to the IBEW/UWUA
MOU, the Buyer shall not be required to assume any Local
Working Conditions but agrees that it shall fulfill all
of its obligations under the IBEW/UWUA MOU with respect
to the creation of, and bargaining over, new Local
Working Conditions.
<PAGE>
(c) Schedule 7.10(c) sets forth the collective
bargaining agreements to which the Sellers are a party
with the BUW in connection with the Purchased Assets (the
"BUW CBAs"), and the Memorandum of Understanding between
the Sellers and certain of their Affiliates and the BUW
("BUW MOU"). With respect to NEPGen Employees who are
represented by the BUW ("BUW Employees") and consistent
with Sellers "best efforts" obligations under the BUW
MOU, the Buyer shall assume the BUW CBA for the duration
of its term. Further, the Buyer will accept and fulfill
all obligations under the BUW MOU designated for the new
owner, including, but not limited to, recognizing the
respective BUW local as the collective bargaining agent
as long as supported by law.
(d) For the period commencing on the Closing Date
and ending 12 months thereafter, the Buyer shall provide
all NEPGen Employees who are not IBEW/UWUA Employees or
BUW Employees ("NEPGen Non-Union Employees") with total
compensation (including, without limitation, base pay,
authorized overtime as set forth in Schedule 7.10(d),
bonuses, and benefits contained in the employee benefit
plans, programs and fringe benefit arrangements
(excluding education reimbursement)) which is, in the
aggregate, at least equivalent in value to the NEPGen Non-
Union Employee's total compensation prior to the Closing.
Such total compensation shall be based upon (x) such
employee's existing individual base pay, (y) authorized
overtime, if applicable, and (z) an average bonus and
benefit component for such employee's salary plan level,
as consistently applied by Seller, apportioned according
to such employee's base pay.
(e) As of the Closing Date, all NEPGen Non-Union
Employees shall cease to participate in the employee
welfare benefit plans (as such term is defined in ERISA)
maintained or sponsored by the Sellers or their
Affiliates (the "Prior Welfare Plans") and shall, if
applicable, commence to participate in welfare benefit
plans of the Buyer or its Affiliates (the "Replacement
Welfare Plans"). The Buyer shall (i) waive all
limitations as to pre-existing condition exclusions and
waiting periods with respect to NEPGen Non-Union
Employees under the Replacement Welfare Plans, other
than, but only to the extent of, limitations or waiting
<PAGE>
periods that were in effect with respect to such
employees under the Prior Welfare Plans and that have not
been satisfied as of the Closing Date, and (ii) provide
each NEPGen Non-Union Employee with credit for any
copayments and deductibles paid prior to the Closing Date
in satisfying any deductible or out-of-pocket
requirements under the Replacement Welfare Plans (on a
pro-rata basis in the event of a difference in plan
years).
(f) NEPGen Non-Union Employees shall be given
credit for all service with the Sellers and their
Affiliates under all employee benefit plans, programs,
and fringe benefit plans, programs, and fringe benefit
arrangements of the Buyer ("Buyer Benefit Plans") in
which they become participants. The service credit given
is for purposes of eligibility, vesting and service
related level of benefits, but not benefit accrual. For
purposes of benefit accrual, NEPGen Non-Union Employees
shall be given credit for all service with the Sellers
and their Affiliates under all Buyer Benefit Plans, but
the ultimate benefits provided under the Buyer Benefit
Plans may be offset by those previously provided by the
Sellers or benefit plans of the Sellers, or by the
benefits accrued under the benefit plans of the Sellers
or otherwise committed to be provided by the Sellers in
the future. Nothing in this Agreement shall preclude the
use of a "Defined Contribution Plan" in substitution for
the "Defined Benefit Plans" maintained by the Sellers.
(g) To the extent allowable by law, the Buyer
shall take any and all necessary action to cause the
trustee of a defined contribution plan of the Buyer or
one of its Affiliates, if requested to do so by a NEPGen
Non-Union Employee, to accept a direct "rollover" of all
or a portion of said employee's distribution (excluding
securities) from the New England Electric System
Companies Incentive Thrift Plan.
(h) In addition to the Buyer's obligations with
respect to the Severance Amount set forth in Section 4.2,
other than NEPGen Non-Union Employees who have previously
received a severance or early retirement benefit package
from NEP or its Affiliates, the Buyer shall pay to each
NEPGen Non-Union Employee whose employment is terminated
by the Buyer or one of its Affiliates within eighteen
<PAGE>
months of the Closing Date a severance benefit package
equivalent to that which would have been provided to such
individual upon such termination by the Sellers or their
Affiliates under the 1997 NEES Companies Special
Severance Plan had such individual remained continuously
employed by the Sellers or their Affiliates and had been
eligible under, and covered by, such plan on the date of
such termination.
(i) The Sellers agree to timely perform and
discharge all requirements under the WARN Act and under
applicable state and local laws and regulations for the
notification of their employees arising from the sale of
the Purchased Assets to the Buyer up to and including the
Closing Date for those employees who will become NEPGen
Employees effective as of the Closing Date. After the
Closing Date, the Buyer shall be responsible for
performing and discharging all requirements under the
WARN Act and under applicable state and local laws and
regulations for the notification of its employees with
respect to the Fossil Assets or the Hydroelectric Assets,
as the case may be.
7.11. Risk of Loss. (a) From the date hereof through
the Closing Date, all risk of loss or damage to the
property included in the Purchased Assets shall be borne
by the Sellers.
(b) If, before the Closing Date all or any portion
of the Purchased Assets are taken by eminent domain or is
the subject of a pending or (to the knowledge of the
Sellers) contemplated taking which has not been
consummated, the Sellers shall notify the Buyer promptly
in writing of such fact. If such taking would create a
Material Adverse Effect, the Buyer and the Sellers shall
negotiate in good faith to settle the loss resulting from
such taking (including, without limitation, by making a
fair and equitable adjustment to the Purchase Price) and,
upon such settlement, consummate the transaction
contemplated by this Agreement pursuant to the terms of
this Agreement. If no such settlement is reached within
sixty (60) days after the Sellers have notified the Buyer
of such taking, then the Buyer or the Sellers may
terminate this Agreement pursuant to Section 11.1(f).
<PAGE>
(c) If, before the Closing Date all or any
material portion of the Purchased Assets are damaged or
destroyed by fire or other casualty, the Sellers shall
notify the Buyer promptly in writing of such fact. If
such damage or destruction would create a Material
Adverse Effect and the Sellers have not notified the
Buyer of their intention to cure such damage or
destruction within fifteen (15) days after its
occurrence, the Buyer and the Sellers shall negotiate in
good faith to settle the loss resulting from such
casualty (including, without limitation, by making a fair
and equitable adjustment to the Purchase Price) and, upon
such settlement, consummate the transactions contemplated
by this Agreement pursuant to the terms of this
Agreement. If no such settlement is reached within sixty
(60) days after the Sellers have notified the Buyer of
such casualty, then the Buyer or the Sellers may
terminate this Agreement pursuant to Section 11.1(f).
7.12. Transfer of the NERC Stock. NEP shall use
its reasonable best efforts to cause the transfer of the
NERC Stock to NEP by no later than the day on which all
conditions to the Closing set forth in Sections 8.1, 8.2
and 8.3 have been satisfied, other than the condition set
forth in Section 8.2(e).
7.13. Standard Offer. Prior to the Closing, the
Buyer shall, upon consultation with NEP, have the right
to submit a Standard Offer Bid on behalf of NEP;
provided, however, that the Buyer shall not submit a
Standard Offer Bid on NEP's behalf for Standard Offer
Service to an Affiliate of the Sellers without the
consent of NEP, which consent shall not unreasonably be
withheld. The Buyer shall not submit a Standard Offer
Bid on NEP's behalf for Standard Offer Service to any
Person who is not an Affiliate of NEP without the consent
of NEP. A successful Standard Offer Bid submitted on
behalf of the Seller shall not relieve the Buyer of its
obligations under each Transition Agreement to provide
"Wholesale Standard Offer Service" (as defined in each
such Transition Agreement). NEP shall not submit a
Standard Offer Bid without the consent of the Buyer.
7.14. Cooperation Relating to Insurance. The
Sellers shall cooperate with the Buyer's efforts to
<PAGE>
obtain "sunrise insurance" with regard to the Purchased
Assets. In addition, the Sellers agree to use reasonable
efforts to assist the Buyer in making any claims against
pre-Closing insurance policies of the Sellers that may
provide coverage related to Assumed Obligations. The
Buyer agrees that it will indemnify Sellers for their
reasonable out of pocket expenses incurred in providing
such assistance and cooperation. Notwithstanding the
foregoing, the Buyer acknowledges that Sellers and their
Affiliates are entitled, in their sole discretion, to
reach settlement agreements with their insurance carriers
regarding claims of the Sellers and their Affiliates with
respect to manufactured gas waste liabilities of the
Sellers and their Affiliates, and that any such
settlement agreements may limit or eliminate any coverage
that may otherwise be available to the Buyer with respect
to Assumed Liabilities described in Sections 2.3(a)(v)
and (vi) hereof. The Buyer further agrees that it will
not interfere with any efforts of the Sellers and their
Affiliates with the aforementioned settlement efforts.
7.15. Granite State Transition Agreement. On or
prior to the Closing Date, Buyer and Granite State
Electric Company shall at the request of Granite State
Electric Company enter into a Wholesale Standard Offer
Service Agreement, in substantially the same form as the
Wholesale Standard Offer Service Agreement dated on the
date of this Agreement, between the Buyer and
Massachusetts Electric Company.
7.16. Tax Clearance Certificates. The Sellers and
Buyer shall cooperate and use their best efforts to cause
the tax clearance certificates described in Schedule 5.20
of this Agreement to be issued by the appropriate taxing
authorities prior to the Closing Date or as soon as
practicable thereafter.
ARTICLE VIII
FOSSIL ASSETS CONDITIONS
8.1. Conditions to Each Party's Obligations to
Effect the Fossil Assets Transaction. The respective
obligations of each party to effect the sale of the
Fossil Assets shall be subject to the fulfillment at or
prior to the Closing Date of the following conditions:
<PAGE>
(a) The waiting period under the HSR Act
applicable to the consummation of the sale of the Fossil
Assets contemplated hereby shall have expired or been
terminated;
(b) No preliminary or permanent injunction or
other order or decree by any federal or state court which
prevents the consummation of the sale of the Fossil
Assets contemplated hereby shall have been issued and
remain in effect (each party agreeing to use its
reasonable best efforts to have any such injunction,
order or decree lifted) and no statute, rule or
regulation shall have been enacted by any State or
Federal government or governmental agency in the United
States which prohibits the consummation of the sale of
the Fossil Assets;
(c) All Federal, State and local government
consents and approvals required for the consummation of
the sale of the Fossil Assets and the Sellers Required
Regulatory Approvals applicable to the Fossil Assets and
the Buyer Required Regulatory Approvals applicable to the
Fossil Assets, shall have been obtained or become Final
Orders (a "Final Order" for all purposes of this
Agreement means a final order after all opportunities for
rehearing are exhausted (whether or not any appeal
thereof is pending) that has not been revised, stayed,
enjoined, set aside, annulled or suspended, with respect
to which any required waiting period has expired; and as
to which all conditions to effectiveness prescribed
therein or otherwise by law, regulation or order have
been satisfied) and such Final Orders shall not impose
materially adverse terms or conditions;
(d) All consents and approvals for the
consummation of the sale of the Fossil Assets
contemplated hereby required under the terms of any note,
bond, mortgage, indenture, contract or other agreement to
which the Sellers or the Buyer, or any of their
subsidiaries, are a party shall have been obtained, other
than those (i) which if not obtained, would not, in the
aggregate, create a Material Adverse Effect, or (ii)
which are governed by the PPA Transfer Agreement, the PSA
Performance Support Agreements or Section 7.4(c); and
<PAGE>
(e) All conditions to the obligations of the
Parties to effect the sale of the Hydroelectric Assets
shall be satisfied or waived.
8.2. Conditions to Obligations of the Buyer. The
obligation of the Buyer to effect the sale of the Fossil
Assets contemplated by this Agreement shall be subject to
the fulfillment at or prior to the Closing Date of the
following additional conditions:
(a) There shall not have occurred and be
continuing a Material Adverse Effect;
(b) The Sellers shall have performed and complied
with in all material respects the covenants and
agreements contained in this Agreement which relate to
the Fossil Assets and are required to be performed and
complied with by the Sellers on or prior to the Closing
Date, and the representations and warranties of the
Sellers which relate to the Sellers or the Fossil Assets
and are set forth in this Agreement shall be true and
correct as of the date of this Agreement and as of the
Closing Date as though made at and as of the Closing
Date;
(c) There shall be no Encumbrances on the Fossil
Assets by virtue of the Indentures or the NERC Note
Agreements;
(d) The Buyer shall have received certificates
from authorized officers of the Sellers, dated the
Closing Date, to the effect that, to the best of such
officers' knowledge, the conditions set forth in Sections
8.2(a), (b) and (c) have been satisfied;
(e) NEES shall have transferred the NERC Stock to
NEP;
(f) New England Power Service Company, a
Massachusetts corporation ("NEPSCO"), shall have assigned
to the Buyer all of its rights and obligations in (i) the
Main Table Agreements as they relate to the IBEW/UWUA
Employees and (ii) the BUW CBAs as they relate to the BUW
Employees, to be employed at or in conjunction with the
Fossil Assets after the Closing Date;
<PAGE>
(g) The Buyer shall have received an opinion from
Skadden, Arps, Slate, Meagher & Flom LLP, or other
counsel reasonably acceptable to Buyer, dated the Closing
Date and satisfactory in form and substance to the Buyer
and its counsel, substantially to the effect that:
(1) The Sellers and NERC are each
corporations duly organized, existing and in good
standing under the laws of their respective states
of incorporation and the Sellers have the corporate
power and authority to execute and deliver this
Agreement and those Ancillary Agreements which
relate to the Fossil Assets and to consummate the
transactions contemplated hereby; and the execution
and delivery of this Agreement and such Ancillary
Agreements and the consummation of the sale of the
Fossil Assets contemplated hereby have been duly
authorized by all requisite corporate action taken
on the part of the Sellers;
(2) this Agreement and those Ancillary
Agreements which relate to the Fossil Assets have
been duly executed and delivered by the Sellers and
(assuming that the Sellers Required Regulatory
Approvals and the Buyer Required Regulatory
Approvals are obtained) are valid and binding
obligations of the Sellers, enforceable against the
Sellers in accordance with their terms, except (A)
that such enforcement may be subject to bankruptcy,
insolvency, reorganization, moratorium or other
similar laws now or hereafter in effect relating to
creditors' rights, and (B) that the remedy of
specific performance and injunctive and other forms
of equitable relief may be subject to certain
equitable defenses and to the discretion of the
court before which any proceeding therefor may be
brought;
(3) the execution and delivery and
performance of this Agreement and the Ancillary
Agreements by the Sellers do not (i) conflict with
the Certificates of Incorporation or Bylaws, as
currently in effect, of the Sellers or (ii) to our
knowledge constitute a violation of or default under
the Applicable Contracts (except that we express no
<PAGE>
opinion as to any covenant, restriction or provision
of any such agreement or instrument with respect to
financial covenants, ratios or tests or any aspect
of the financial condition or results of operations
of the Sellers). "Applicable Contracts" mean those
agreements or instruments set forth on an attached
Schedule and which have been identified to us as all
the agreements and instruments which are material to
the business or financial condition of the Sellers;
(4) the Bill of Sale and other documents
described in Section 4.3 are in proper form to
transfer to the Buyer title to the Fossil Assets;
(5) no declaration, filing or registration
with, or notice to, or authorization, consent or
approval of any governmental authority is necessary
for the consummation by the Sellers of the Closing
other than (i) the Sellers Required Regulatory
Approvals, all of such Sellers Required Regulatory
Approvals which are applicable to the sale of the
Fossil Assets hereunder having been obtained and
being in full force and effect with such terms and
conditions as shall have been imposed by any
applicable governmental authority, and (ii) such
declarations, filings, registrations, notices,
authorizations, consents or approvals which, if not
obtained or made, would not, in the aggregate create
a Material Adverse Effect; and
(6) The Share has been duly and validly
authorized and validly issued, is fully paid and non-
assessable, and was not issued in violation of the
preemptive rights of any stockholder of NERC. NEP
is the owner of such share of NERC Stock, free and
clear of any perfected security interest and, to our
knowledge, any other security interests, claims,
liens or encumbrances. Assuming issuance by the SEC
of an appropriate order under the Holding Company
Act, NEP has the absolute and unrestricted right,
power, authority and capacity to sell the NERC Stock
to the Buyer.
As to any matter contained in such opinion which
involves the laws of any jurisdiction other than the
Federal laws of the United States or the laws of the
<PAGE>
Commonwealth of Massachusetts, such counsel may rely upon
opinions of counsel admitted in such other jurisdictions.
Any opinions relied upon by such counsel as aforesaid
shall be delivered together with the opinion of such
counsel. Such opinion may expressly rely as to matters
of fact upon certificates furnished by the Sellers and
appropriate officers and directors of the Sellers and by
public officials;
(h) The Buyer shall have received the
qualifications or approvals set forth in Section
6.3(b)(i) and (ii) hereof; and
(i) The Buyer shall be reasonably satisfied that
all material Environmental Permits and material Permits
will be transferred to the Buyer or obtained by the Buyer
on or before the Closing Date.
8.3. Conditions to Obligations of the Sellers.
The obligation of the Sellers to effect the sale of the
Fossil Assets contemplated by this Agreement shall be
subject to the fulfillment at or prior to the Closing
Date of the following additional conditions:
(a) The Buyer shall have performed in all
material respects its covenants and agreements contained
in this Agreement which relate to the Fossil Assets and
are required to be performed on or prior to the Closing
Date;
(b) The representations and warranties of the
Buyer which relate to the Buyer of Fossil Assets and are
set forth in this Agreement shall be true and correct as
of the date of this Agreement and as of the Closing Date
as though made at and as of the Closing Date;
(c) The Sellers shall have received a certificate
from an authorized officer of the Buyer, dated the
Closing Date, to the effect that, to the best of such
officer's knowledge, the conditions set forth in Sections
8.3(a) and (b) have been satisfied;
(d) The Buyer shall have assumed, as set forth in
Section 7.10, all of the applicable obligations under the
Main Table Agreements and the BUW CBAs as they relate to
union employees to be employed at or in conjunction with
the Fossil Assets after the Closing Date;
<PAGE>
(e) The FERC shall have approved the Stipulation
and Agreement filed in FERC Docket No. ER-97-678-000 for
Massachusetts Electric Company dated May 28, 1997 and the
Stipulation and Agreement filed in FERC Docket No. ER-97-
680-000 for Narragansett Electric Company dated May 30,
1997; and said Stipulation and Agreements shall be and
shall continue to be in full force and effect; and
(f) The Sellers shall have received an opinion
from Weil, Gotshal & Manges LLP, counsel for the Buyer,
dated the Closing Date and satisfactory in form and
substance to the Sellers and their counsel, substantially
to the effect that:
(1) The Buyer is a corporation duly
organized, existing and in good standing under the
laws of the State of Delaware and has the corporate
power and authority to execute and deliver this
Agreement and those Ancillary Agreements which relate
to the Fossil Assets and to consummate the
transactions contemplated hereby; and the execution
and delivery of this Agreement and such Ancillary
Agreements and the consummation of the sale of the
Fossil Assets contemplated hereby have been duly
authorized by all requisite corporate action taken on
the part of the Buyer;
(2) this Agreement and those Ancillary
Agreements which relate to the Fossil Assets have been
duly executed and delivered by the Buyer and (assuming
that the Sellers Required Regulatory Approvals and the
Buyer Required Regulatory Approvals are obtained) are
valid and binding obligations of the Buyer,
enforceable against the Buyer in accordance with their
terms, except (A) that such enforcement may be subject
to bankruptcy, insolvency, reorganization, moratorium
or other similar laws now or hereafter in effect
relating to creditors' rights and (B) that the remedy
of specific performance and injunctive and other forms
of equitable relief may be subject to certain
equitable defenses and to the discretion of the court
before which any proceeding therefor may be brought;
(3) the execution and delivery and
performance of this Agreement and the Ancillary
<PAGE>
Agreements by the Buyer does not (i) conflict with the
Certificate of Incorporation or Bylaws, as currently
in effect, of the Buyer or (ii) to our knowledge
constitute a violation of or default under the
Applicable Contracts (except that we express no
opinion as to any covenant, restriction or provision
of any such agreement or instrument with respect to
financial covenants, ratios or tests or any aspect of
the financial condition or results of operations of
the Buyer). "Applicable Contracts" mean those
agreements or instruments set forth on an attached
Schedule and which have been identified to us as all
the agreements and instruments which are material to
the business or financial condition of the Buyer;
(4) the Instruments of Assumption and other
instruments described in Section 4.4 are in proper
form for the Buyer to assume the Assumed Fossil
Obligations; and
(5) no declaration, filing or registration
with, or notice to, or authorization, consent or
approval of any governmental authority is necessary
for the consummation by the Buyer of the Closing other
than the Buyer Required Regulatory Approvals, all of
such Buyer Required Regulatory Approvals which are
applicable to the sale of the Fossil Assets hereunder
having been obtained and being in full force and
effect with such terms and conditions as shall have
been imposed by any applicable governmental authority.
As to any matter contained in such opinion which
involves the laws of any jurisdiction other than the
federal laws of the United States and the Commonwealth of
Massachusetts, such counsel may rely upon opinions of
counsel admitted in such other jurisdictions. Any
opinions relied upon by such counsel as aforesaid shall
be delivered together with the opinion of such counsel.
Such opinion may expressly rely as to matters of facts
upon certificates furnished by appropriate officers and
directors of the Buyer and its subsidiaries and by public
officials.
<PAGE>
ARTICLE IX
HYDROELECTRIC ASSETS CONDITIONS
9.1. Conditions to Each Party's Obligations to
Effect the Hydroelectric Assets Transactions. The
respective obligations of each party to effect the sale
of the Hydroelectric Assets shall be subject to the
fulfillment at or prior to the Closing Date of the
following conditions:
(a) The waiting period under the HSR Act
applicable to the sale of the Hydroelectric Assets
contemplated hereby shall have expired or been
terminated;
(b) No preliminary or permanent injunction or
other order or decree by any federal or state court which
prevents the consummation of the sale of the
Hydroelectric Assets contemplated hereby shall have been
issued and remain in effect (each party agreeing to use
its reasonable best efforts to have any such injunction,
order or decree lifted) and no statute, rule or
regulation shall have been enacted by any State or
Federal government or governmental agency in the United
States which prohibits the consummation of the sale of
the Hydroelectric Assets;
(c) All Federal, State and local government
consents and approvals required for the consummation of
the sale of the Hydroelectric Assets and the Sellers
Required Regulatory Approvals applicable to the
Hydroelectric Assets and the Buyer Required Regulatory
Approvals applicable to the Hydroelectric Assets, shall
have been obtained or become Final Orders and such Final
Orders shall not impose materially adverse terms or
conditions;
(d) All consents and approvals for the
consummation of the sale of the Hydroelectric Assets
contemplated hereby required under the terms of any note,
bond, mortgage, indenture, contract or other agreement to
which the Sellers or the Buyer, or any of their
Subsidiaries, are a party shall have been obtained, other
<PAGE>
than those (i) which if not obtained, would not, in the
aggregate, create a Material Adverse Effect, or (ii)
which are governed by the PSA Performance Support
Agreements or Section 7.4(c); and
(e) All conditions to the obligations of the
Parties to effect the sale of the Fossil Assets shall be
satisfied or waived.
9.2. Conditions to Obligations of the Buyer. The
obligation of the Buyer to effect the sale of the
Hydroelectric Assets contemplated by this Agreement shall
be subject to the fulfillment at or prior to the Closing
Date of the following additional conditions:
(a) There shall not have occurred and be
continuing a Material Adverse Effect;
(b) The Sellers shall have performed and complied
with in all material respects the covenants and
agreements contained in this Agreement which relate to
the Hydroelectric Assets and are required to be performed
and complied with by the Sellers on or prior to the
Closing Date, and the representations and warranties of
the Sellers which relate to the Sellers or the
Hydroelectric Assets and are set forth in this Agreement
shall be true and correct as of the date of this
Agreement and as of the Closing Date as though made at
and as of the Closing Date;
(c) There shall be no Encumbrances on the
Hydroelectric Assets by virtue of the Indentures;
(d) The Buyer shall have received certificates
from authorized officers of the Sellers, dated the
Closing Date, to the effect that, to the best of such
officers' knowledge, the conditions set forth in Sections
8.2(a), (b) and (c) have been satisfied;
(e) NEPSCO shall have assigned to the Buyer all
of its rights and obligations in the Main Table
Agreements as they relate to the IBEW/UWUA Employees to
be employed at or in conjunction with the Hydroelectric
Assets after the Closing Date;
<PAGE>
(f) The Buyer shall have received an opinion from
Skadden, Arps, Slate, Meagher & Flom LLP, dated the
Closing Date and satisfactory in form and substance to
the Buyer and its counsel, substantially to the effect
that:
(1) NEP and Narragansett are corporations
duly organized, existing and in good standing under
the laws of the Commonwealth of Massachusetts and the
State of Rhode Island, respectively, and have the
corporate power and authority to execute and deliver
this Agreement and those Ancillary Agreements which
relate to the Hydroelectric Assets and to consummate
the transactions contemplated hereby; and the
execution and delivery of this Agreement and such
Ancillary Agreements and the consummation of the sale
of the Hydroelectric Assets contemplated hereby have
been duly authorized by all requisite corporate action
taken on the part of the Sellers;
(2) this Agreement and those Ancillary
Agreements which relate to the Hydroelectric Assets
have been duly executed and delivered by the Sellers
and (assuming that the Sellers Required Regulatory
Approvals and the Buyer Required Regulatory Approvals
are obtained) are valid and binding obligations of the
Sellers, enforceable against the Sellers in accordance
with their terms, except (A) that such enforcement may
be subject to bankruptcy, insolvency, reorganization,
moratorium or other similar laws now or hereafter in
effect relating to creditors' rights, and (B) that the
remedy of specific performance and injunctive and
other forms of equitable relief may be subject to
certain equitable defenses and to the discretion of
the court before which any proceeding therefor may be
brought;
(3) the execution and delivery and
performance of this Agreement and the Ancillary
Agreements by the Sellers do not (i) conflict with the
Certificates of Incorporation or Bylaws, as currently
in effect, of the Sellers or (ii) to our knowledge
constitute a violation of or default under the
Applicable Contracts (except that we express no
opinion as to any covenant, restriction or provision
<PAGE>
of any such agreement or instrument with respect to
financial covenants, ratios or tests or any aspect of
the financial condition or results of operations of
the Sellers). "Applicable Contracts" mean those
agreements or instruments set forth on an attached
Schedule and which have been identified to us as all
the agreements and instruments which are material to
the business or financial condition of the Sellers;
(4) the applicable Bill of Sale and other
documents described in Section 4.3, are in proper form
to transfer to the Buyer title to the Hydroelectric
Assets; and
(5) no declaration, filing or registration
with, or notice to, or authorization, consent or
approval of any governmental authority is necessary
for the consummation by NEP of the Closing other than
(i) the Sellers Required Regulatory Approvals, all of
such Sellers Required Regulatory Approvals which are
applicable to the sale of the Hydroelectric Assets
hereunder having been obtained and being in full force
and effect with such terms and conditions as shall
have been imposed by any applicable governmental
authority, and (ii) such declarations, filings,
registrations, notices, authorizations, consents or
approvals which, if not obtained or made, would not,
in the aggregate create a Material Adverse Effect.
As to any matter contained in such opinion which
involves the laws of any jurisdiction other than the
Federal laws of the United States or the laws of the
Commonwealth of Massachusetts, such counsel may rely upon
opinions of counsel admitted in such other jurisdictions.
Any opinions relied upon by such counsel as aforesaid
shall be delivered together with the opinion of such
counsel. Such opinion may expressly rely as to matters
of fact upon certificates furnished by the Sellers and
appropriate officers and directors of the Sellers and by
public officials; and
(g) The Buyer shall have received the
qualifications or approvals set forth in Section
6.3(b)(i) and (ii) hereof.
<PAGE>
9.3. Conditions to Obligations of the Sellers.
The obligation of the Sellers to effect the sale of the
Hydroelectric Assets contemplated by this Agreement shall
be subject to the fulfillment at or prior to the Closing
Date of the following additional conditions:
(a) The Buyer shall have performed in all
material respects its covenants and agreements contained
in this Agreement and which relate to the Hydroelectric
Assets and are required to be performed on or prior to
the Closing Date;
(b) The representations and warranties of the
Buyer which relate to the Buyer or the Hydroelectric
Assets and are set forth in this Agreement shall be true
and correct as of the date of this Agreement and as of
the Closing Date as though made at and as of the Closing
Date;
(c) The Sellers shall have received a certificate
from an authorized officer of the Buyer, dated the
Closing Date, to the effect that, to the best of such
officer's knowledge, the conditions set forth in Sections
9.3(a) and (b) have been satisfied;
(d) The Buyer shall have assumed, as set forth in
Section 7.10(b), all of the applicable obligations under
the Main Table Agreements as they relate to IBEW/UWUA
Employees to be employed at or in conjunction with the
Hydroelectric Assets after the Closing Date;
(e) The FERC shall have approved the Stipulation
and Agreement filed in FERC Docket No. ER-97-678-000 for
Massachusetts Electric Company dated May 28, 1997 and the
Stipulation and Agreement filed in FERC Docket No. ER-97-
680-000 for Narragansett Electric Company dated May 30,
1997; and Stipulation and Agreement shall be and shall
continue to be in full force and effect; and
(f) The Sellers shall have received an opinion
from Weil, Gotshal & Manges LLP, counsel for the Buyer,
<PAGE>
dated the Closing Date and satisfactory in form and
substance to the Sellers and their counsel, substantially
to the effect that:
(1) The Buyer is a corporation duly
organized, existing and in good standing under the
laws of the State of Delaware and has the corporate
power and authority to execute and deliver this
Agreement and those Ancillary Agreements which
relate to the Hydroelectric Assets and to consummate
the transactions contemplated hereby; and the
execution and delivery of this Agreement and such
Ancillary Agreements and the consummation of the
sale of the Hydroelectric Assets contemplated hereby
have been duly authorized by all requisite corporate
action taken on the part of the Buyer;
(2) this Agreement and those Ancillary
Agreements which relate to the Hydroelectric Assets
have been duly executed and delivered by the Buyer
and (assuming that the Sellers Required Regulatory
Approvals and the Buyer Required Regulatory
Approvals are obtained) are valid and binding
obligations of the Buyer, enforceable against the
Buyer in accordance with their terms, except (A)
that such enforcement may be subject to bankruptcy,
insolvency, reorganization, moratorium or other
similar laws now or hereafter in effect relating to
creditors' rights and (B) that the remedy of
specific performance and injunctive and other forms
of equitable relief may be subject to certain
equitable defenses and to the discretion of the
court before which any proceeding therefor may be
brought;
(3) the execution and delivery and
performance of this Agreement and the Ancillary
Agreements by the Buyer does not (i) conflict with
the Certificate of Incorporation or Bylaws, as
currently in effect, of the Buyer or (ii) to our
knowledge constitute a violation of or default under
the Applicable Contracts (except that we express no
opinion as to any covenant, restriction or provision
of any such agreement or instrument with respect to
financial covenants, ratios or tests or any aspect
of the financial condition or results of operations
<PAGE>
of the Buyer). "Applicable Contracts" mean those
agreements or instruments set forth on an attached
Schedule and which have been identified to us as all
the agreements and instruments which are material to
the business or financial condition of the Buyer;
(4) the Instruments of Assumption and other
instruments described in Section 4.4 are in proper
form for the Buyer to assume the Assumed
Hydroelectric Obligations; and
(5) no declaration, filing or registration
with, or notice to, or authorization, consent or
approval of any governmental authority is necessary
for the consummation by the Buyer of the Closing
other than the Buyer Required Regulatory Approvals,
all of such Buyer Required Regulatory Approvals
which are applicable to the sale of the
Hydroelectric Assets hereunder having been obtained
and being in full force and effect with such terms
and conditions as shall have been imposed by any
applicable governmental authority.
As to any matter contained in such opinion which
involves the laws of any jurisdiction other than the
federal laws of the United States and the Commonwealth of
Massachusetts, such counsel may rely upon opinions of
counsel admitted in such other jurisdictions. Any
opinions relied upon by such counsel as aforesaid shall
be delivered together with the opinion of such counsel.
Such opinion may expressly rely as to matters of facts
upon certificates furnished by appropriate officers and
directors of the Buyer and its subsidiaries and by public
officials.
ARTICLE X
INDEMNIFICATION
10.1. Indemnification. The Sellers will
severally, not jointly, and not severally and jointly,
indemnify, defend and hold harmless the Buyer from and
against any and all claims, demands or suits (by any
Person), losses, liabilities, damages (including
consequential or special damages), obligations, payments,
<PAGE>
costs and expenses (including, without limitation, the
costs and expenses of any and all actions, suits,
proceedings, assessments, judgments, settlements and
compromises relating thereto and reasonable attorneys'
fees and reasonable disbursements in connection
therewith) to the extent the foregoing are not covered by
insurance (each, an "Indemnifiable Loss"), asserted
against or suffered by the Buyer relating to, resulting
from or arising out of (i) any breach by the Sellers of
any covenant or agreement of the Sellers contained in
this Agreement or the representations and warranties
contained in Sections 5.1, 5.2 or 5.3 hereof, (ii) the
Excluded Liabilities, (iii) any relationship or payment
obligation of the Sellers resulting from or contained in
the PSA Performance Support Agreements, or Section 7.4(c)
hereof or, (iv) any obligation imposed on the Buyer to
make payments for the delivery of electric energy from
any of the Fossil Facilities or Hydroelectric Facilities
to the associated Point of Interconnection defined and
identified in the Continuing Site Agreement other than
the Annual Facilities Charge, as specified in the
Continuing Site Agreement (v) or noncompliance by the
Sellers with any bulk sales or transfer laws as provided
in Section 12.11; provided, however, that the Sellers
shall have no liability pursuant to this Section 10.1(a)
for Indemnifiable Losses arising from any breach or
breaches by the Sellers of Section 7.1(a) or any failure
to update Schedule 2.4 as required pursuant to Section
7.9 hereof, unless and until the aggregate Indemnifiable
Losses incurred by the Buyer and attributable thereto
exceeds $5,000,000, in which case the Sellers shall be
liable for all such losses, but only to the extent they
exceed $5,000,000.
(b) The Buyer will indemnify, defend and hold
harmless the Sellers from and against any and all
Indemnifiable Losses asserted against or suffered by the
Sellers relating to, resulting from or arising out of
(i) any breach by the Buyer of any covenant or agreement
of the Buyer contained in this Agreement or the
representations and warranties contained in Sections 6.1,
6.2 and 6.3 hereof, (ii) the Assumed Obligations, (iii)
any relationship or payment obligation of the Buyer
resulting from or contained in the PSA Performance
Support Agreements or Section 7.4(c) or (iv) any
liabilities incurred, directly or indirectly, in
<PAGE>
connection with any contracts, agreements or other
arrangements entered into pursuant to Section
7.1(d)(iii).
(c) Any Person entitled to receive
indemnification under this Agreement (an "Indemnitee")
having a claim under these indemnification provisions
shall make a good faith effort to recover all losses,
damages, costs and expenses from insurers of such
Indemnitee under applicable insurance policies so as to
reduce the amount of any Indemnifiable Loss hereunder.
The amount of any Indemnifiable Loss shall be reduced
(i) to the extent that Indemnitee receives any insurance
proceeds with respect to an Indemnifiable Loss and
(ii) to take into account any net Tax benefit recognized
by the Indemnitee arising from the recognition of the
Indemnifiable Loss and any payment actually received with
respect to an Indemnifiable Loss.
(d) The expiration, termination or extinguishment
of any covenant or agreement shall not affect the
parties' obligations under this Section 10.1 if the
Indemnitee provided the Person required to provide
indemnification under this Agreement (the "Indemnifying
Party") with proper notice of the claim or event for
which indemnification is sought prior to such expiration,
termination or extinguishment.
(e) Except to the extent provided in Section
7.8(d)(3) hereof, which Section shall govern the matters
covered therein, the rights and remedies of the Sellers
and the Buyer under this Article X are exclusive and in
lieu of any and all other rights and remedies which the
Sellers and the Buyer may have under this Agreement or
otherwise for monetary relief with respect to (i) any
breach or failure to perform any covenant or agreement
set forth in this Agreement or (ii) the Assumed
Obligations or the Excluded Liabilities, as the case may
be and (iii) any relationship or payment obligation
resulting from the PSA Performance Support Agreements or
Section 7.4(c).
(f) Buyer and Sellers each agree that
notwithstanding any provisions in this Agreement to the
contrary, all parties to this Agreement retain their
remedies at law or in equity with respect to willful or
intentional breaches of this Agreement.
<PAGE>
10.2. Defense of Claims. (a) If any Indemnitee
receives notice of the assertion of any claim or of the
commencement of any claim, action, or proceeding made or
brought by any Person who is not a party to this
Agreement or any Affiliate of a party to this Agreement
(a "Third Party Claim") with respect to which
indemnification is to be sought from an Indemnifying
Party, the Indemnitee will give such Indemnifying Party
reasonably prompt written notice thereof, but in any
event not later than ten (10) calendar days after the
Indemnitee's receipt of notice of such Third Party Claim.
Such notice shall describe the nature of the Third Party
Claim in reasonable detail and will indicate the
estimated amount, if practicable, of the Indemnifiable
Loss that has been or may be sustained by the Indemnitee.
The Indemnifying Party will have the right to participate
in or, by giving written notice to the Indemnitee, to
elect to assume the defense of any Third Party Claim at
such Indemnifying Party's own expense and by such
Indemnifying Party's own counsel, and the Indemnitee will
cooperate in good faith in such defense at such
Indemnitee's own expense.
(b) If within ten (10) calendar days after an
Indemnitee provides written notice to the Indemnifying
Party of any Third Party Claim the Indemnitee receives
written notice from the Indemnifying Party that such
Indemnifying Party has elected to assume the defense of
such Third Party Claim as provided in the last sentence
of Section 10.2(a), the Indemnifying Party will not be
liable for any legal expenses subsequently incurred by
the Indemnitee in connection with the defense thereof;
provided, however, that if the Indemnifying Party fails
to take reasonable steps necessary to defend diligently
such Third Party Claim within twenty (20) calendar days
after receiving notice from the Indemnitee that the
Indemnitee believes the Indemnifying Party has failed to
take such steps, the Indemnitee may assume its own
defense, and the Indemnifying Party will be liable for
all reasonable expenses thereof. Without the prior
written consent of the Indemnitee, the Indemnifying Party
will not enter into any settlement of any Third Party
Claim which would lead to liability or create any
financial or other obligation on the part of the
Indemnitee for which the Indemnitee is not entitled to
<PAGE>
indemnification hereunder. If a firm offer is made to
settle a Third Party claim without leading to liability
or the creation of a financial or other obligation on the
part of the Indemnitee for which the Indemnitee is not
entitled to indemnification hereunder and the
Indemnifying Party desires to accept and agree to such
offer, the Indemnifying Party will give written notice to
the Indemnitee to that effect. If the Indemnitee fails
to consent to such firm offer within ten (10) calendar
days after its receipt of such notice, the Indemnitee may
continue to contest or defend such Third Party Claim and,
in such event, the maximum liability of the Indemnifying
Party as to such Third Party Claim will be the amount of
such settlement offer, plus reasonable costs and expenses
paid or incurred by the Indemnitee up to the date of such
notice.
(c) Any claim by an Indemnitee on account of an
Indemnifiable Loss which does not result from a Third
Party Claim (a "Direct Claim") will be asserted by giving
the Indemnifying Party reasonably prompt written notice
thereof, stating the nature of such claim in reasonable
detail and indicating the estimated amount, if
practicable, but in any event not later than ten (10)
calendar days after the Indemnitee becomes aware of such
Direct Claim, and the Indemnifying Party will have a
period of thirty (30) calendar days within which to
respond to such Direct Claim. If the Indemnifying Party
does not respond within such thirty (30) calendar day
period, the Indemnifying Party will be deemed to have
accepted such claim. If the Indemnifying Party rejects
such claim, the Indemnitee will be free to seek
enforcement of its rights to indemnification under this
Agreement.
(d) If the amount of any Indemnifiable Loss, at
any time subsequent to the making of an indemnity payment
in respect thereof, is reduced by recovery, settlement or
otherwise under or pursuant to any insurance coverage, or
pursuant to any claim, recovery, settlement or payment by
or against any other entity, the amount of such
reduction, less any costs, expenses or premiums incurred
in connection therewith (together with interest thereon
from the date of payment thereof at the prime rate then
in effect of the Bank of Boston), will promptly be repaid
by the Indemnitee to the Indemnifying Party. Upon making
<PAGE>
any indemnity payment, the Indemnifying Party will, to
the extent of such indemnity payment, be subrogated to
all rights of the Indemnitee against any third party in
respect of the Indemnifiable Loss to which the indemnity
payment relates; provided, however, that (i) the
Indemnifying Party will then be in compliance with its
obligations under this Agreement in respect of such
Indemnifiable Loss and (ii) until the Indemnitee recovers
full payment of its Indemnifiable Loss, any and all
claims of the Indemnifying Party against any such third
party on account of said indemnity payment is hereby made
expressly subordinated and subjected in right of payment
to the Indemnitee's rights against such third party.
Without limiting the generality or effect of any other
provision hereof, each such Indemnitee and Indemnifying
Party will duly execute upon request all instruments
reasonably necessary to evidence and perfect the above-
described subrogation and subordination rights, and
otherwise cooperate in the prosecution of such claims at
the direction of the Indemnifying Party. Nothing in this
Section 10.2(d) shall be construed to require any party
hereto to obtain or maintain any insurance coverage.
(e) A failure to give timely notice as provided
in this Section 10.2 will not affect the rights or
obligations of any party hereunder except if, and only to
the extent that, as a result of such failure, the party
which was entitled to receive such notice was actually
prejudiced as a result of such failure.
ARTICLE XI
TERMINATION AND ABANDONMENT
11.1. Termination. (a) This Agreement may be
terminated at any time prior to the Closing Date by
mutual written consent of the Sellers and the Buyer.
(b) This Agreement may be terminated by the
Sellers or the Buyer if the Closing contemplated hereby
shall have not occurred on or before the first
anniversary of the date of this Agreement (the
"Termination Date"); provided that the right to terminate
this Agreement under this Section 11.1(b)(i) shall not be
available to any party whose failure to fulfill any
<PAGE>
obligation under this Agreement has been the cause of, or
resulted in, the failure of either Closing to occur on or
before such date; and provided, further, that if on the
first anniversary of the date of this Agreement the
conditions to the Closings set forth in either Section
8.1(c) or Section 9.1(c) shall not have been fulfilled
but all other conditions to the Closing shall be
fulfilled or shall be capable of being fulfilled, then
the Termination Date shall be the day which is eighteen
months from the date of this Agreement.
(c) This Agreement may be terminated by either
the Sellers or the Buyer if (i) any governmental or
regulatory body, the consent of which is a condition to
the obligations of the Sellers and the Buyer to
consummate the Closing shall have determined not to grant
its or their consent and all appeals of such
determination shall have been taken and have been
unsuccessful, (ii) one or more courts of competent
jurisdiction in the United States or any State shall have
issued an order, judgment or decree permanently
restraining, enjoining or otherwise prohibiting the
Closing, and such order, judgment or decree shall have
become final and nonappealable or (iii) any statute, rule
or regulation shall have been enacted by any State or
Federal government or governmental agency in the United
States which prohibits the consummation of the Closing.
(d) This Agreement may be terminated by the
Buyer, if there has been a material violation or breach
by the Sellers of any agreement, representation or
warranty contained in this Agreement which has rendered
the satisfaction of any condition to the obligations of
the Buyer to effect the Closing impossible and such
violation or breach has not been waived by the Buyer.
(e) This Agreement may be terminated by the
Sellers, if there has been a material violation or breach
by the Buyer of any agreement, representation or warranty
contained in this Agreement which has rendered the
satisfaction of any condition to the obligations of the
Sellers to effect the Closing impossible and such
violation or breach has not been waived by the Sellers.
(f) This Agreement may be terminated by either of
the Sellers or the Buyer in accordance with the
provisions of Section 7.11(b) or (c).
<PAGE>
11.2. Procedure and Effect of Termination.
In the event of termination of this Agreement and
abandonment of the transactions contemplated hereby by
either or both of the parties pursuant to Section 11.1,
written notice thereof shall forthwith be given by the
terminating party to the other party and this Agreement
shall terminate and the transactions contemplated hereby
shall be abandoned, without further action by any of the
parties hereto. If this Agreement is terminated as
provided herein:
(a) said termination shall be the sole remedy of
the parties hereto with respect to breaches of any
agreement, representation or warranty contained in this
Agreement and none of the parties hereto nor any of their
respective trustees, directors, officers or Affiliates,
as the case may be, shall have any liability or further
obligation to the other party or any of their respective
trustees, directors, officers or Affiliates, as the case
may be, pursuant to this Agreement, except in each case
as stated in this Section 11.2 and in Sections 7.2(b),
7.3 and 7.7; and
(b) all filings, applications and other
submissions made pursuant to this Agreement, to the
extent practicable, shall be withdrawn from the agency or
other Person to which they were made.
ARTICLE XII
MISCELLANEOUS PROVISIONS
12.1. Amendment and Modification. Subject to
applicable law, this Agreement may be amended, modified
or supplemented only by written agreement of the Sellers
and the Buyer.
12.2. Waiver of Compliance; Consents. Except as
otherwise provided in this Agreement, any failure of any
of the parties to comply with any obligation, covenant,
agreement or condition herein may be waived by the party
entitled to the benefits thereof only by a written
instrument signed by the party granting such waiver, but
such waiver or failure to insist upon strict compliance
<PAGE>
with such obligation, covenant, agreement or condition
shall not operate as a waiver of, or estoppel with
respect to, any subsequent or other failure.
Notwithstanding anything in this Agreement to the
contrary, (i) the condition set forth in Section 8.3(d)
cannot be waived by the Sellers without the consent of
each of the BUW, the IBEW and the UWUA and (ii) the
condition set forth in Section 9.3(d) cannot be waived by
the Sellers without the consent of each of the IBEW and
the UWUA.
12.3. No Survival. Subject to the provisions of
Section 11.2, each and every representation, warranty and
covenant contained in this Agreement (other than the
covenants contained in Sections 3.2, 7.2(b), 7.3, 7.4,
7.7, 7.8, 7.10, 7.14 and 7.16 and in Articles X and XI
(which covenants shall survive in accordance with their
terms) and other than the representations and warranties
contained in Sections 5.1, 5.2 and 5.3 (which
representations and warranties shall survive for eighteen
months from the Closing)) shall expire with, and be
terminated and extinguished by the consummation of the
sale of the Purchased Assets and the transfer of the
Assumed Obligations pursuant to this Agreement and such
representations, warranties and covenants shall not
survive the Closing Date; and none of the Sellers, the
Buyer or any officer, director, trustee or Affiliate of
any of them shall be under any liability whatsoever with
respect to any such representation, warranty or covenant.
12.4. Notices. All notices and other
communications hereunder shall be in writing and shall be
deemed given if delivered personally or by facsimile
transmission, telexed or mailed by overnight courier or
registered or certified mail (return receipt requested),
postage prepaid, to the parties at the following
addresses (or at such other address for a party as shall
be specified by like notice; provided that notices of a
change of address shall be effective only upon receipt
thereof):
<PAGE>
(a) If to the Sellers, to:
New England Power Company
The Narragansett Electric Company
c/o New England Power Service Company
25 Research Drive
Westborough, MA 01582
Facsimile: (508) 389-5498
Attention: Mr. Michael E. Jesanis
with a copy to:
Skadden, Arps, Slate, Meagher & Flom LLP
919 Third Avenue
New York, NY 10022
Facsimile: (212) 735-2000
Attention: Sheldon S. Adler, Esq.
(b) if to the Buyer, to:
USGen Acquisition Corporation
7500 Old Georgetown Road, 13th Floor
Bethesda, MD 20814
Facsimile: (301) 718-6913
Attention: Stephen A. Herman, Esq.
General Counsel
with a copy to:
Weil, Gotshal & Manges LLP
700 Louisiana, Suite 1600
Houston, TX 77024
Facsimile: (713) 224-9511
Attention: Alan Gover, Esq.
12.5. Assignment. This Agreement and all of the
provisions hereof shall be binding upon and inure to the
benefit of the parties hereto and their respective
successors and permitted assigns, but neither this
Agreement nor any of the rights, interests or obligations
hereunder shall be assigned by any party hereto,
including by operation of law without the prior written
consent of the other party, nor is this Agreement
intended to confer upon any other Person except the
parties hereto any rights or remedies hereunder;
<PAGE>
provided, however that NEPGen Employees may have claims
under Sections 2.3(a)(iv) and 7.10. Notwithstanding the
foregoing, no provision of this Agreement shall create
any third party beneficiary rights in any employee or
former employee of the Sellers (including any beneficiary
or dependent thereof) in respect of continued employment
or resumed employment, and no provision of this Agreement
shall create any rights in any such Persons in respect of
any benefits that may be provided, directly or
indirectly, under any employee benefit plan or
arrangement except as expressly provided for thereunder.
Notwithstanding the foregoing, (i) the Buyer may assign
all of its rights and obligations hereunder to any wholly
owned Subsidiary (direct or indirect) of PG&E Corporation
and upon the Sellers' receipt of notice from Buyer of any
such assignment, the Buyer will be released from all
liabilities and obligations hereunder, accrued and
unaccrued, such assignee will be deemed to have assumed,
ratified, agreed to be bound by and perform all such
liabilities and obligations, and all references herein to
"Buyer" shall thereafter be deemed references to such
assignee, in each case without the necessity for further
act or evidence by the parties hereto or such assignee;
provided, however, that no such assignment and assumption
shall release the Buyer from its liabilities and
obligations hereunder unless the assignee shall have
acquired all or substantially all of the Buyer's assets;
provided, further, however, that no such assignment and
assumption shall relieve or in any way discharge PG&E
Corporation from the performance of its duties and
obligations under the Guaranty dated as of the date of
this Agreement executed by PG&E Corporation, and (ii) the
Buyer or its permitted assignee may assign, transfer,
pledge or otherwise dispose of its rights and interests
hereunder to a trustee or lending institution(s) for the
purposes of financing or refinancing the Purchased
Assets, including upon or pursuant to the exercise of
remedies under such financing or refinancing, or by way
of assignments, transfers, conveyances or dispositions in
lieu thereof; provided, however, that no such assignment
or disposition shall relieve or in any way discharge the
Buyer or such assignee from the performance of its duties
and obligations under this Agreement. The Sellers agree
to execute and deliver such documents as may be
reasonably necessary to accomplish any such assignment,
transfer, conveyance, pledge or disposition of rights
<PAGE>
hereunder so long as the Sellers' rights under this
Agreement are not thereby altered, amended, diminished or
otherwise impaired.
12.6. Governing Law. This Agreement shall be
governed by and construed in accordance with the laws of
the Commonwealth of Massachusetts (regardless of the laws
that might otherwise govern under applicable
Massachusetts principles of conflicts of law) as to all
matters, including but not limited to matters of
validity, construction, effect, performance and remedies.
12.7. Counterparts. This Agreement may be executed
in two or more counterparts, each of which shall be
deemed an original, but all of which together shall
constitute one and the same instrument.
12.8. Interpretation. The article and section
headings contained in this Agreement are solely for the
purpose of reference, are not part of the agreement of
the parties and shall not in any way affect the meaning
or interpretation of this Agreement.
12.9. Schedules and Exhibits. All Exhibits and
Schedules referred to herein are intended to be and
hereby are specifically made a part of this Agreement.
12.10. Entire Agreement. This Agreement, the
Confidentiality Agreement, the Ancillary Agreements, the
Wholesale Sales Agreement and the Transition Agreements
including the Exhibits, Schedules, documents,
certificates and instruments referred to herein or
therein, embody the entire agreement and understanding of
the parties hereto in respect of the transactions
contemplated by this Agreement. There are no
restrictions, promises, representations, warranties,
covenants or undertakings, other than those expressly set
forth or referred to herein or therein. It is expressly
acknowledged and agreed that there are no restrictions,
promises, representations, warranties, covenants or
undertakings contained in any material made available to
the Buyer pursuant to the terms of the Confidentiality
Agreement (including the Information Memorandum, dated
January, 1997, or the Request for Proposal, dated May,
1997, previously made available to the Buyer by the
Sellers and Merrill Lynch & Co.). This Agreement
<PAGE>
supersedes all prior agreements and understandings
between the parties with respect to such transactions
other than the Confidentiality Agreement.
12.11. Bulk Sales or Transfer Laws. The Buyer
acknowledges that the Sellers will not comply with the
provision of any bulk sales or transfer laws of any
jurisdiction in connection with the transactions
contemplated by this Agreement. The Buyer hereby waives
compliance by the Sellers with the provisions of the bulk
sales or transfer laws of all applicable jurisdictions.
<PAGE>
IN WITNESS WHEREOF, the Sellers and the Buyer have
caused this agreement to be signed by their respective
duly authorized officers as of the date first above
written.
NEW ENGLAND POWER COMPANY
/s/
By
Name: Michael E. Jesanis
Title:Treasurer
THE NARRAGANSETT ELECTRIC
COMPANY
/s/
By
Name: Alfred D. Houston
Title:Vice President and
Treasurer
USGEN ACQUISITION CORPORATION
/s/
By
Name: Joseph P. Kearney
Title: President
<PAGE>
TABLE OF CONTENTS
-----------------
Page
----
ARTICLE I
DEFINITIONS
1.1. Definitions 1
ARTICLE II
PURCHASE AND SALE
2.1. The Sale 18
2.2. Excluded Assets 18
2.3. Assumed Obligations 19
2.4. Excluded Liabilities 23
ARTICLE III
PURCHASE PRICE
3.1. Purchase Price 26
3.2. Purchase Price Adjustment 26
3.3. Allocation of Purchase Price 28
3.4. Additional Payment Amount 29
3.5. Proration 31
ARTICLE IV
THE CLOSING
4.1. Time and Place of Closing 32
4.2. Payment of Purchase Price 33
4.3. Deliveries by the Sellers 34
4.4. Deliveries by the Buyer 35
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF THE SELLERS
5.1. Organization; Qualification; Matters
Regarding NERC 36
<PAGE>
Page
----
5.2. Authority Relative to this Agreement 37
5.3. Consents and Approvals; No Violation 38
5.4. Reports 40
5.5. Financial Statements 40
5.6. Undisclosed Liabilities 40
5.7. Absence of Certain Changes or Events 41
5.8. Title and Related Matters 41
5.9. Leases 41
5.10. Insurance 42
5.11. Environmental Matters 42
5.12. Labor Matters 43
5.13. ERISA; Benefit Plans 44
5.14. Real Estate 45
5.15. Condemnation 45
5.16. Certain Contracts and Arrangements 45
5.17. Legal Proceedings, etc 46
5.18. Permits 47
5.19. Regulation as a Utility 47
5.20. Taxes 48
5.21. NERC Holdings 51
ARTICLE VI
REPRESENTATIONS AND WARRANTIES OF THE BUYER
6.1. Organization 51
6.2. Authority Relative to this Agreement 51
6.3. Consents and Approvals; No Violation 52
6.4. Regulation as a Utility 53
6.5. Availability of Funds 53
ARTICLE VII
COVENANTS OF THE PARTIES
7.1. Conduct of Business Relating to the Purchased Asse
ts 53
7.2. Access to Information 58
7.3. Expenses 61
7.4. Further Assurances 61
7.5. Public Statements 63
7.6. Consents and Approvals 64
7.7. Fees and Commissions 65
<PAGE>
Page
----
7.8. Tax Matters 65
7.9. Supplements to Schedules 73
7.10. Employees 73
7.11. Risk of Loss 78
7.12. Transfer of the NERC Stock 79
7.13. Standard Offer 79
7.14. Cooperation Relating to Insurance 79
7.15. Granite State Transition Agreement 80
7.16 Tax Clearance Certificates 80
ARTICLE VIII
FOSSIL ASSETS CONDITIONS
8.1. Conditions to Each Party's Obligations
to Effect the Fossil Assets Transactions. 80
8.2. Conditions to Obligations of the Buyer 82
8.3. Conditions to Obligations of the Sellers 85
ARTICLE IX
HYDROELECTRIC ASSETS CONDITIONS
9.1. Conditions to Each Party's Obligations to
Effect the Hydroelectric Assets Transactions. 88
9.2. Conditions to Obligations of the Buyer 89
9.3. Conditions to Obligations of the Sellers 92
ARTICLE X
INDEMNIFICATION
10.1. Indemnification 94
10.2. Defense of Claims 97
ARTICLE XI
TERMINATION AND ABANDONMENT
11.1. Termination 99
11.2. Procedure and Effect of Termination 101
<PAGE>
Page
----
ARTICLE XII
MISCELLANEOUS PROVISIONS
12.1. Amendment and Modification 101
12.2. Waiver of Compliance; Consents 101
12.3. No Survival 102
12.4. Notices 102
12.5. Assignment 103
12.6. Governing Law 105
12.7. Counterparts 105
12.8. Interpretation 105
12.9. Schedules and Exhibits. 105
12.10. Entire Agreement 105
12.11. Bulk Sales or Transfer Laws 106
<PAGE>
February 10, 1997 Exhibit 10.2
Mr. Joseph P. Kearney
President and CEO
U.S. Generating Company
7500 Old Georgetown Road
Bethesda, MD 20814-6161
Dear Joe:
On behalf of PG&E Corporation, I am pleased to modify our January
24, 1997, invitation to you to join our organization as
president and chief executive officer of U.S. Generating Company
and senior vice president of PG&E Corporation, reporting to me.
This position will commence on completion of our purchase of
Bechtel's interests in U. S. Generating (USGen). We have opened
discussions with Bechtel on this and are optimistic that we can
achieve this objective expeditiously.
Your initial target annual total compensation is calculated to be
$1,313,295, and includes the following:
1. Annual base salary of $400,000 ($33,333.33 monthly) subject
to possible increases through our Merit Review Plan.
2. Target annual bonus of $180,000 which equals 45% of your
salary under the annual Incentive Plan. Your actual bonus
dollars can range from $0 to $360,000, based on your performance
relative to established goals.
3. Annual award of 5,000 performance units under PG&E's
Performance Unit Plan (PUP). The value of these units is tied to
the price of the corporation's common stock. The estimated value
of this award is $100,000 based on present value of $20.00 per
share.
4. A stock option grant of 8,500 shares of common stock with
dividend equivalents. The estimated value of this award is
$61,795 based on a present value of $7.27 per share.
5. A stock option grant of 200,000 shares of common stock
without dividend equivalents. The estimated value of this award
is $556,000 based on a present value of $2.78 per share.
6. Annual perquisite allowance of $15,500.
7. Participation in health and welfare benefit plans comparable
to your current plans.
8. Participation in PG&E Enterprises Supplemental Executive
Retirement Plan with credited service back to your date of
hire at USGen.
<PAGE>
9. Participation in PG&E's Deferred Compensation Plan.
10. Four weeks of paid vacation per year.
As we have discussed, some of these compensation elements, as
well as election as an officer of PG&E Corporation, are subject
to Board of Directors approval.
We have discussed the mechanism for resolving LTI and the net
payment due on change of control as a way of dealing with any
amount you would have received under paragraph 3(a) or 3(b) of
the unexecuted October 28, 1996, draft Release Agreement and
Amendment of Amended and Restated Employment Agreement. Attached
is an illustration of how we understand that calculation would be
made.
Joe, Stan and I are really looking forward to your joining PG&E
Corporation's top management team. With you as part of the team,
we will be making the key decisions to consolidate the gas and
electric wholesale commodity marketing parts of the several
businesses in the PG&E Corporation family of Companies. As we
have discussed, these are exciting times in our business and we
are going forward with the vision, the resources and the team to
be successful. We want you on this team.
I am very pleased to extend this offer to you and hope you will
find it acceptable. We hope to present this recommendation to
the Board at its next meeting. For that reason, we would
appreciate a response no later than February 11, 1997.
Sincerely,
ROBERT D. GLYNN, JR.
<PAGE>
U.S. Generating Company
Approximate Kearney Payout Calculation
USGen & LTI Valuations as of 7/1/96
($ in millions)
Case 1
---------
Project Value (1) [*]
Less:
Prior Costs minus Prior Distributions (2) [*]
Contingent Equity Costs (3) [*]
Opportunity Costs (4) [*]
-------
Costs Net of Distributions [*]
Valuation before tax $ [*]
Tax Payment on Sale (5):
Project Value [*]
USGen Tax Basis (6) [*]
Taxable Income [*]
Income Tax Rate [*] [*]
--------
After Tax Value $ [*]
Kearney's Gross Payment 5% $ [*]
Less:
Previous LTI Payments (7):
Paid in August 1996, under new LTI [*]
Payments under previous LTI Program [*]
----------
[*]
-------
Payment on Sale $ [*]
=======
Remaining estimated LTI payment (7) & (8) [*]
-------
Payment on Sale less future vested
LTI payment $ [*]
=======
Notes: See attached for explanation of notes
* Confidential treatment of omitted information has been requested.
Omitted information has been filed separately with the Commission.
<PAGE>
U.S. Generating Company
Approximate Kearney Payout Calculation
USGen & LTI Valuations as of 7/1/96
Notes Explaining Kearney's Payout Calculation
(1) Project Value would be a result of the transaction between PG&E
and Bechtel. For this illustration, Project Value represents the
potential sales/market value of USGen that Morgan Stanley and Goldman
Sachs were required to calculate for the Leopard and LTI valuations
as of June 30, 1996. Goldman Sachs' valuation of the projects for
LTI purposes was $[*]. Morgan Stanley's market valuation was $[*];
which included additional tax benefits a buyer could realize
from a tax basis step-up.
(2) Present Value of project cash inflows and outflows at a [*]% cost
of equity capital (assumed blended trigger rate).
(3) Contingent Equity Costs - [*]% charged on outstanding balance,
then PV adjusted at project's trigger rate.
(4) Opportunity Costs - outstanding balance charged at projects
trigger rate less cash reinvestment rate.
(5) The contract states that in the event of a sale, the valuation
amount used to calculate Kearney's payment will be reduced by any
income taxes that PG&EE and Bechtel would have been required to pay
if the sales proceeds had actually been realized. For purposes of
this calculation, Kearny % will be subtracted from Project Value for
tax calculation purposes.
(6) USGen Tax Basis is calculated using PG&EE's and Bechtel's equity
investment in the each project partnership which amount is increased
by partnership taxable earnings but decreased by partnership tax
losses and cash distributions. USGen's low tax basis is a result of
projects having high tax depreciation deductions in early years that
PG&E has been able to deduct when calculating its federal and state
income taxes.
(7) Section 3(d) of the proposed and unsigned revised Kearney's
employment agreement requires the payment to be reduced by previous
LTI payments. LTI payments have been made under two different LTI
programs: The first LTI plan was approved by the PG&EE Board in
November, 1993, and was effective for years 1989 through 1994. The
second LTI plan, called the U.S. Generating Company Value Creation
Incentive Plan, was approved by the PG&EE Board on November 16, 1995,
and is effective for years 1995 through 1999. Three payments are to
be made which are prorated over the 5 year period. The first payment
was for the value created from January 1, 1995 through June 30, 1996,
at 40% of the total value created, the second payment is due December
31, 1997 at 70% of the total value created and the final 100% payment
is due on December 31, 1999.
(8) Remaining estimated payout under the current USGen Value Creation
program from July 1, 1996 through December 31, 1999, which amount
is to be fully vested and redeemed upon change of control of the
company.
* Confidential treatment of omitted information has been requested.
Omitted information has been filed separately with the Commission.
<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>
