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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934 [NO FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 [NO FEE REQUIRED]
COMMISSION FILE NUMBER 033-73160
CALPINE CORPORATION
(A DELAWARE CORPORATION)
I.R.S. EMPLOYER IDENTIFICATION NO. 77-0212977
50 WEST SAN FERNANDO STREET
SAN JOSE, CALIFORNIA 95113
TELEPHONE: (408) 995-5115
Securities registered pursuant to Section 12(b) of the Act: Calpine Corporation
Common Stock, $0.001 par value Registered on the New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark whether the Registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of the Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates of the
Registrant as of March 4, 1998: $334.2 million
Common stock outstanding as of March 4, 1998: 20,104,890
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.
(1) Designated portions of the Proxy Statement relating to
the 1998 Annual Meeting of Shareholders:... Part III (Items 10, 11 and 12)
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CALPINE CORPORATION
FORM 10-K
ANNUAL REPORT
FOR THE YEAR ENDED DECEMBER 31, 1997
TABLE OF CONTENTS
PART 1
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PAGE
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<S> <C> <C>
ITEM 1. Business.................................................... 1
ITEM 2. Properties.................................................. 41
ITEM 3. Legal Proceedings........................................... 42
ITEM 4. Submission of Matters To A Vote of Security Holders......... 43
PART II
ITEM 5. Market for Registrant's Common Equity and Related 43
Stockholder Matters.......................................
ITEM 6. Selected Financial Data..................................... 43
ITEM 7. Management's Discussion and Analysis of Financial Condition 43
and Results of Operations.................................
ITEM 8. Financial Statements and Supplementary Data................. 43
ITEM 9. Changes In and Disagreements with Accountants and Financial 43
Disclosure................................................
PART III
ITEM 10. Executive Officers, Directors and Key Employees............. 43
ITEM 11. Executive Compensation...................................... 43
ITEM 12. Security Ownership of Certain Beneficial Owners and 43
Management................................................
ITEM 13. Certain Relationships and Related Transactions.............. 43
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 44
8-K.......................................................
Signatures ............................................................ 51
Index to Consolidated Financial Statements and Schedules................... F-1
Exhibit
Index......
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ITEM 1. BUSINESS
Except for historical financial information contained herein, the matters
discussed in this annual report may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding the intent, belief or current
expectations of the Company and its management. Prospective investors are
cautioned that any such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties; actual results
could differ materially from those indicated by such forward-looking statements.
Among the important factors that could cause actual results to differ materially
from those indicated by such forward-looking statements are: (i) that the
information is of a preliminary nature and may be subject to further adjustment,
(ii) those risks and uncertainties identified under "Risk Factors" included in
Item 1. Business in this Annual Report on Form 10-K, (iii) the possible
unavailability of financing, (iv) risks related to the development, acquisition
and operation of power plants, (v) the impact of avoided cost pricing, energy
price fluctuations and gas price increases, (vi) the impact of curtailment,
(vii) the seasonal nature of the Company's business, (viii) start-up risks, (ix)
general operating risks, (x) the dependence on third parties, (xi) risks
associated with international investments, (xii) risks associated with the power
marketing business, (xiii) changes in government regulation, (xiv) the
availability of natural gas, (xv) the effects of competition, (xvi) the
dependence on senior management, (xvii) volatility in the Company's stock price,
(xviii) fluctuations in quarterly results and seasonality, and (xix) other risks
identified from time to time in the Company's reports and registration
statements filed with the Securities and Exchange Commission.
OVERVIEW
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") is engaged in the acquisition, development,
ownership and operation of power generation facilities and the sale of
electricity and steam, principally in the United States. The Company currently
has interests in 23 power plants and steam fields having an aggregate capacity
of 2,613 megawatts. The Company currently sells electricity and steam to 16
utility and other customers, principally under long-term power and steam sales
agreements, generated by power generation facilities located in six states and
Mexico. In addition, the Company has a 240 megawatt gas-fired power plant
currently under construction in Pasadena, Texas and an investment in a 169
megawatt gas-fired power plant currently under construction in Dighton,
Massachusetts. Since its inception in 1984, the Company has developed
substantial expertise in all aspects of electric power generation. The Company's
vertical integration has resulted in significant growth in recent years as the
Company has applied its extensive engineering, construction management,
operations, fuel management and financing capabilities to successfully implement
its acquisition and development program. The Company's strategy is to capitalize
on opportunities in the power market through an ongoing program to acquire,
develop, own and operate electric power generation facilities, as well as
marketing power and energy services to utilities and other end users.
The Company's net interest in power generation facilities has increased
from 297 megawatts in 1992 to 1,981 megawatts in 1997, including the facilities
currently under construction. Total assets have increased from $55.4 million as
of December 31, 1992 to $1.4 billion as of December 31, 1997. The Company's
revenue has increased to $276.3 million for 1997, representing a five-year
compound annual growth rate of 48% since 1992. The Company's EBITDA (as defined
herein) for 1997 increased to $172.6 million from $9.9 million in 1992,
representing a five-year compound annual growth rate of 77%.
THE MARKET
The power generation industry represents the third largest industry in the
United States, with an estimated end user market of over $200 billion of
electricity sales and 3,300 gigawatt hours of production in 1997. In response to
increasing customer demand for access to low-cost electricity and enhanced
services, new regulatory initiatives are currently being adopted or considered
at both state and federal levels to increase competition in the domestic power
generation industry. To date, such initiatives are under consideration at the
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federal level and in approximately 45 states. In April 1996, the Federal Energy
Regulatory Commission ("FERC") adopted Order No. 888, opening wholesale power
sales to competition and providing for open and fair electric transmission
services by public utilities. In addition, the California Public Utilities
Commission ("CPUC") has issued an electric industry restructuring decision,
which originally provided for commencement of deregulation and implementation of
customer choice of electricity supplier by January 1, 1998, and is currently
scheduled to commence on April 1, 1998. The Company believes that industry
trends and such regulatory initiatives will lead to the transformation of the
existing market, which is largely characterized by electric utility monopolies
having old, inefficient high-cost generating facilities, selling to a captive
customer base, to a more competitive market where end users may purchase
electricity from a variety of suppliers, including non-utility generators, power
marketers, public utilities and others. The Company believes that these market
trends will create substantial opportunities for companies such as themselves
that are low cost power producers and have an integrated power services
capability which enables them to produce and sell energy to customers at
competitive rates.
The Company also believes that these market trends will result in the
disposition of power generation facilities by utilities, independent power
producers and industrial companies. Numerous utilities have announced their
intentions to sell their power generation facilities. Many independent producers
operating a limited number of power plants are seeking to dispose of such plants
in response to competitive pressures, and industrial companies are selling their
power plants to redeploy capital in their core businesses. The Company believes
that this consolidation will continue in the highly fragmented independent power
industry.
STRATEGY
The Company's objective is to become a leading power company by
capitalizing on emerging market opportunities in the domestic power markets. The
key elements of the Company's strategy are as follows:
Expand and diversify its domestic portfolio of power projects. In pursuing
its growth strategy, the Company intends to focus on opportunities where it is
able to capitalize on its extensive management and technical expertise to
implement a fully integrated approach to the acquisition, development and
operation of power generation facilities. This approach includes design,
engineering, procurement, finance, construction, management, fuel and resource
acquisition, operations and power marketing, which the Company believes provides
it with a competitive advantage.
Acquisition of power plants. The Company has significantly expanded and
diversified its project portfolio through the acquisition of power generation
facilities. Since 1993, the Company has completed transactions involving
thirteen gas-fired cogeneration facilities and two steam fields. As a result of
these transactions, the Company has more than quadrupled its aggregate power
generation capacity and substantially diversified its fuel mix during this
period. The Company intends to continue to pursue an active acquisition program.
Development of merchant power plants. The Company is also pursuing the
development of highly efficient, low-cost power plants that seek to take
advantage of inefficiencies in the electricity market. The Company intends to
sell all or a portion of the power generated by such merchant plants into the
competitive market through a portfolio of short, medium and long-term power
sales agreements. As part of Calpine's initial effort to develop merchant
plants, the Company has a 240 megawatt gas-fired power generation facility
currently under construction in Pasadena, Texas and a 169 megawatt gas-fired
power generation facility currently under construction in Dighton,
Massachusetts. The Company currently plans to develop additional low-cost,
gas-fired facilities in California, Texas, New England and other high-priced
power markets.
Enhance the performance and efficiency of existing power projects. The
Company continually seeks to maximize the power generation potential of its
operating assets and minimize its operating and maintenance expenses and fuel
costs. To date, the Company's power generation facilities have operated at an
average availability of approximately 97%. The Company believes that achieving
and maintaining a low-cost of production will be increasingly important to
compete effectively in the power generation market.
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DESCRIPTION OF FACILITIES
The Company currently has interests in 23 power generation facilities and
steam fields with a current aggregate capacity of approximately 2,613 megawatts,
consisting of fifteen gas-fired power plants with a total capacity of 2,127
megawatts, three geothermal power generation facilities (which include a steam
field and a power plant) with a total capacity of 67 megawatts and five
geothermal steam fields that supply utility power plants with a total current
capacity of approximately 419 megawatts. In addition, the Company has a 240
megawatt gas-fired power generation facility under construction in Pasadena,
Texas, and an investment in a 169 megawatt gas-fired power generation facility
currently under construction in Dighton, Massachusetts. Each of the power
generation facilities currently in operation produces electricity for sale to a
utility or other thirdparty end user. Thermal energy produced by the gas-fired
cogeneration facilities is sold to governmental and industrial users, and steam
produced by the geothermal steam fields is sold to utility-owned-power plants.
The gas-fired and geothermal power generation projects in which the Company
has an interest produce electricity, thermal energy and steam that are typically
sold pursuant to long-term, take and pay power or steam sales agreements
generally having original terms of 20 or 30 years. Revenue from a power sales
agreement usually consists of two components: energy payments and capacity
payments. Energy payments are based on a power plant's net electrical output
where payment rates may be determined by a schedule of prices covering a fixed
number of years under the power sales agreement, after which payment rates are
usually indexed to the fuel costs of the contracting utility or to general
inflation indices. Capacity payments are based on a power plant's net electrical
output and/or its available capacity. Energy payments are made for each
kilowatt-hour of energy delivered, while capacity payments, under certain
circumstances, are made whether or not any electricity is delivered. The Company
is paid for steam supplied by its steam fields on the basis of the amount of
electrical energy produced by, or steam delivered to, the contracting utility's
power plants.
The Company currently provides operating and maintenance services for 16 of
the 23 power plants and steam fields in which the Company has an interest. Such
services include the operation of power plants, geothermal steam fields, wells
and well pumps, gathering systems and gas pipelines. The Company also supervises
maintenance, materials, purchasing and inventory control, manages cash flow,
trains staff and prepares operating and maintenance manuals for each power
generation facility. As a facility develops an operating history, the Company
analyzes its operation and may modify or upgrade equipment or adjust operating
procedures or maintenance measures to enhance the facility's reliability or
profitability. These services are performed under the terms of an operating and
maintenance agreement pursuant to which the Company is generally reimbursed for
certain costs, is paid an annual operating fee and may also be paid an incentive
fee based on the performance of the facility. The fees payable to the Company
are generally subordinated to any lease payments or debt service obligations of
non-recourse financing for the project.
In order to provide fuel for the gas-fired power generation facilities in
which the Company has an interest, natural gas reserves are acquired or natural
gas is purchased from third parties under supply agreements. The Company
attempts to structure a gas-fired power facility's fuel supply agreement so that
gas costs have a direct relationship to the fuel component of revenue energy
payments.
Certain power generation facilities in which the Company has an interest
have been financed primarily with non-recourse project financing that is
structured to be serviced out of the cash flows derived from the sale of
electricity, thermal energy and/or steam produced by such facilities and
provides that the obligations to pay interest and principal on the loans are
secured almost solely by the capital stock or partnership interests, physical
assets, contracts and/or cash flow attributable to the entities that own the
facilities. The lenders under non-recourse project financing generally have no
recourse for repayment against the Company or any assets of the Company or any
other entity other than foreclosure on pledges of stock or partnership interests
and the assets attributable to the entities that own the facilities.
Substantially all of the power generation facilities in which the Company
has an interest are located on sites which are leased on a long-term basis. The
Company currently holds interests in geothermal leaseholds in The Geysers that
produce steam for sale under steam sales agreements and for use in producing
electricity from its wholly-owned geothermal power generation facilities.
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The continued operation of power generation facilities and steam fields
involves many risks, including the breakdown or failure of power generation
equipment, transmission lines, pipelines or other equipment or processes and
performance below expected levels of output or efficiency. To date, the
Company's power plants have operated at an average availability of 97%. Although
from time to time the Company's power generation facilities have experienced
certain equipment breakdowns or failures, such breakdowns or failures have not
had a material adverse effect on the operation of such facilities or on the
Company's results of operations. Although the Company's facilities contain
certain redundancies and back-up mechanisms, there can be no assurance that any
such breakdown or failure would not prevent the affected facility or steam field
from performing under applicable power and/or steam sales agreements. In
addition, although insurance is maintained to protect against certain of these
operating risks, the proceeds of such insurance may not be adequate to cover
lost revenue or increased expenses, and, as a result, the entity owning such
power generation facility or steam field may be unable to service principal and
interest payments under its financing obligations and may operate at a loss. A
default under such a financing obligation could result in the Company losing its
interest in such power generation facility or steam field.
Insurance coverage for each power generation facility includes commercial
general liability, workers' compensation, employer's liability and property
damage coverage, which generally contains business interruption insurance
covering debt service and continuing expenses for a period ranging from 12 to 18
months.
The Company believes that each of the currently operating power generation
facilities in which the Company has an interest is exempt from financial and
rate regulation as a public utility under federal and state laws.
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Set forth below is certain information regarding the Company's operating
power plants, pending power plant acquisitions, development projects and
operating steam fields as of March 4, 1998.
POWER PLANTS
<TABLE>
<CAPTION>
TERM OF
POWER NAMEPLATE CALPINE CALPINE NET COMMENCEMENT POWER
GENERATION CAPACITY INTEREST INTEREST OF COMMERCIAL POWER SALES
POWER PLANT TECHNOLOGY (MEGAWATTS)(1) PERCENTAGE (MEGAWATTS) OPERATION PURCHASER AGREEMENT
----------- ---------- -------------- ---------- ----------- ------------- ----------------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
OPERATING POWER PLANTS
Texas City........... Gas-Fired 450 50% 225 1987 TUEC 2002
UCC(2) 2003
Clear Lake........... Gas-Fired 377 50% 188.5 1984 TNP 2004
HL&P 2005
HCCG(3) 2004
Gordonsville......... Gas-Fired 240 50% 120 1994 VEPCO(4) 2024
Lockport............. Gas-Fired 184 11.36% 20.9 1992 GM 2007
NYSEG(5)
Auburndale........... Gas-Fired 150 50% 75 1994 FPC(16) 2013
Sumas(6)............. Gas-Fired 125 70% 87.5 1993 Puget Sound and 2013
Electric Company
King City............ Gas-Fired 120 100% 120 1989 PG&E(17) 2019
Gilroy............... Gas-Fired 120 100% 120 1988 PG&E 2018
Kennedy International
Airport............ Gas-Fired 107 50% 53.5 1995 Port Authority(7) 2015
Bethpage............. Gas-Fired 57 100% 57 1989 NG Corp. 2004
LILCO(8)
Greenleaf 1.......... Gas-Fired 49.5 100% 49.5 1989 PG&E 2019
Greenleaf 2.......... Gas-Fired 49.5 100% 49.5 1989 PG&E 2019
Stony Brook.......... Gas-Fired 40 50% 20 1995 SUNY 2015
LILCO(9)
Agnews............... Gas-Fired 29 20% 5.8 1990 PG&E 2021
Watsonville.......... Gas-Fired 28.5 100% 28.5 1990 PG&E 2009
West Ford Flat....... Geothermal 27 100% 27 1988 PG&E 2008
Bear Canyon.......... Geothermal 20 100% 20 1988 PG&E 2008
Aidlin............... Geothermal 20 5% 1 1989 PG&E 2009
PENDING ACQUISITIONS
Pittsburgh........... Gas-Fired 70 100% 70 1966 Dow Chemical n/a
Corporation
PROJECTS UNDER CONSTRUCTION
Pasadena(10)......... Gas-Fired 240 100% 240 1998 Phillips 2018
Dighton(11).......... Gas-Fired 169 50% 84.5 1999 Merchant n/a
</TABLE>
STEAM FIELDS
<TABLE>
<CAPTION>
APPROXIMATE CALPINE CALPINE NET COMMENCEMENT
CAPACITY INTEREST INTEREST OF COMMERCIAL UTILITY ESTIMATED
STEAM FIELD (MEGAWATTS)(12) PERCENTAGE (MEGAWATTS) OPERATION PURCHASER LIFE(13)
----------- --------------- ---------- ----------- ------------- ------------- ---------
<S> <C> <C> <C> <C> <C> <C>
Thermal Power Company 140 100% 140 1960 PG&E 2018
PG&E Unit 13 75 100% 75 1980 PG&E 2018
PG&E Unit 16 74 100% 74 1985 PG&E 2018
SMUDGEO #1 50 100% 50 1983 SMUD 2018
Cerro Prieto 80 100%(14) 80 1973 Comision 2000(15)
Federal de
Electricidad
Electric
</TABLE>
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(1) Nameplate capacity may not represent the actual output for a facility at
any particular time.
(2) The power purchasers for the Texas City Power Plant are the Texas Utilities
Electric Company ("TUEC") and the Union Carbide Corporation ("UCC").
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(3) The power purchasers for the Clear Lake Power Plant are the Texas-New
Mexico Power Company ("TNP"), the Houston Lighting and Power Company
("HL&P") and the Hoechst Celanese Chemical Group, Inc. ("HCCG").
(4) The power purchaser for the Gordonsville Power Plant is Virginia Electric
and Power Company ("VEPCO").
(5) The power purchasers for the Lockport Power Plant are General Motors
("GM"), and New York State Electric and Gas ("NYSEG").
(6) See Power Plants-Sumas Power Plants for a description of the Company's
interest in the Sumas partnership and current sales of power by the Sumas
Power Plant.
(7) Electricity generated by the Kennedy International Airport Power Plant is
sold to the Port Authority of New York and New Jersey ("Port Authority")
and excess energy is sold to other utility customers.
(8) Electricity generated by the Bethpage Power Plant is sold to the Northrup
Grumman Corporation ("NG Corp"), and excess energy is sold to Long Island
Lighting Corporation ("LILCo").
(9) Electricity generated by the Stony Brook Power Plant is sold to the State
University of New York at Stony Brook ("SUNY"), and excess energy is sold
to LILCo.
(10) The Pasadena Power Plant is currently under construction and is expected to
commence commercial operation in July 1998. Approximately 90 megawatts will
be sold to Phillips Petroleum Company ("Phillips"), with the remaining
available electricity generated to be sold into the open market.
(11) The Dighton Power Plant is currently under construction and is expected to
commence commercial operation in early 1999. The Company invested $16.0
million in the facility, which entitles the Company to receive a preferred
payment stream at a rate of 12.07% per annum on its investment. Based on
the Company's current estimates, this preferred payment stream will
represent approximately 50% of project cash flow beginning at the
commencement of commercial operation. A merchant plant is a power
generation facility that sells all or a portion of its electricity into the
competitive market rather than pursuant to long-term power sales
agreements.
(12) Capacity is expected to gradually diminish as the production of the related
steam fields declines.
(13) Other than the Cerro Prieto Steam Field, the steam sales agreements remain
in effect so long as steam is produced in commercial quantities. There can
be no assurance that the estimated life shown accurately predicts actual
productive capacity of the steam fields.
(14) See Steam Fields-Cerro Prieto Steam Fields for a description of the
Company's interest in and current sales of steam by the Cerro Prieto Steam
Field.
(15) Represents the actual termination of the steam sales agreement.
(16) Florida Power Company ("FPC").
(17) Pacific Gas & Electric Company ("PG&E").
POWER PLANTS
Texas City and Clear Lake Power Plants
On June 23, 1997, the Company completed the acquisition of a 50% equity
interest in the Texas City and the Clear Lake Cogeneration facilities for a
total purchase price of $35.4 million. The Company acquired its 50% interest in
these plants through the acquisition of 50% of the capital stock of Enron
Dominion Cogen Corp., subsequently renamed Texas Cogeneration Company ("TCC")
from Enron Power Corp., which is a wholly-owned subsidiary of Enron Corp.
("Enron"). The other 50% shareholder in TCC is Dominion Cogen, Inc., a
wholly-owned subsidiary of Dominion Energy, Inc. which in turn is a wholly-owned
subsidiary of Dominion Resources, Inc., which is the parent company of VEPCO. In
addition to the purchase of 50% of the stock of TCC, the Company, through its
wholly-owned subsidiary, Calpine Finance Company ("CFC"), purchased from the
existing lenders the $155.6 million of outstanding non-recourse project
financing incurred by TCC in connection with the Texas City Power Plant
(approximately $53.0 million) and the Clear Lake Power Plant (approximately
$102.6 million). The acquisition of the capital stock of TCC and the purchase of
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the outstanding debt from the existing lenders were financed with approximately
$125.0 million of non-recourse project financing provided by The Bank of Nova
Scotia and $70.0 million of equity provided by the Company. The non-recourse
project financing matures on June 22, 1998 and bears interest at London
Interbank Offered Rate ("LIBOR") plus an agreed margin, currently 7.2% per
annum. The Company currently expects to refinance this non-recourse project
financing before June 22, 1998.
Texas City Power Plant -- The Texas City Power Plant is a 450 megawatt
gas-fired cogeneration facility located in Texas City, Texas. The Texas City
Power Plant includes three Westinghouse W-501D5 combustion turbines, three
Econotherm heat recovery steam generators and one Hitachi steam turbine. The
Texas City Power Plant commenced commercial operation in June 1987. In 1997, the
Texas City Power Plant operated at an average availability of 92.9%.
Electricity generated by the Texas City Power Plant is sold under two
separate long-term agreements to (i) TUEC under a power sales agreement
terminating on September 30, 2002 and (ii) Union Carbide Company ("UCC") under a
steam and electricity services agreement terminating on June 30, 1999. Each
agreement contains payment provisions for capacity and electric energy payments.
Under a steam and electricity services agreement expiring October 19, 2003,
the Texas City Power Plant will supply UCC with 300,000 lbs/hr of steam on a
monthly average basis, with the required supply of steam not exceeding 600,000
lbs/hr at any given time. It is necessary for the Texas City Power Plant to
provide a certain amount of thermal energy to a host facility in order to
maintain its qualifying facility ("QF") status.
Natural gas requirements for the Texas City Power Plant are allocated
between UCC, DEI Texas, Inc. ("DEI"), an affiliate of Dominion Cogen Inc., and
Enron Capital & Trade Resources Corporation ("ECT") pursuant to a contractual
arrangement. UCC and DEI currently provide approximately 25% and 56%,
respectively, of the fuel requirements of the Texas City Power Plant. The three
fuel contracts are effective through June 30, 1999. Under the fuel contracts,
approximately 19% of the total fuel requirements of the Texas City Power Plant
is supplied at spot market prices. The remainder is purchased at fixed rates set
forth in the contracts.
The Texas City Power Plant is operated and maintained by the Company under
a one-year operating and maintenance agreement with automatic renewal
provisions, pursuant to which the Company is reimbursed for certain costs and is
entitled to a fixed annual fee and an incentive payment based on project
performance.
The Texas City Power Plant is located on approximately 9 acres of land in
Texas City, Texas.
During 1997, the Texas City Power Plant generated approximately
2,704,481,000 kilowatt-hours of electric energy for sale to TUEC and UCC and
approximately $197.6 million of revenue.
Clear Lake Power Plant -- The Clear Lake Power Plant is a 377 megawatt
gas/hydrogen-fired cogeneration facility located in Pasadena, Texas. The Clear
Lake Power Plant includes three Westinghouse W-501D5 combustion turbines, three
Vogt heat recovery steam generators and two Westinghouse steam turbines. The
Clear Lake Power Plant commenced commercial operation in December 1984. In 1997,
the Clear Lake Power Plant operated at an average availability of 97.4%.
Electricity generated by the Clear Lake Power Plant is sold under three
separate long-term agreements to (i) TNP under an original 20-year power sales
agreement terminating in 2004, (ii) HL&P under an original 10- year power sales
agreement terminating in 2005, and (iii) HCCG under an original 10-year power
sales agreement terminating in 2004. Each power sales agreement contains payment
provisions for capacity and energy payments.
Under a steam purchase and sale agreement expiring August 31, 2004, the
Clear Lake Power Plant will supply up to 900,000 lbs/hr of steam to HCCG. It is
necessary for the Clear Lake Power Plant to provide a certain amount of thermal
energy to a host facility in order to maintain its QF status.
The natural gas for the Clear Lake Power Plant is purchased primarily from
TCC, which receives its fuel from ECT. In addition, the facility burns hydrogen
provided by HCCG, amounting to about 5% of the Clear Lake Power Plant's total
fuel requirements.
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The Clear Lake Power Plant is operated by the Company under a one-year
operating and maintenance agreement with automatic renewal provisions, pursuant
to which the Company is reimbursed for certain costs and is entitled to a fixed
annual fee and an incentive payment based on project performance.
The Clear Lake Power Plant is located on approximately 21 acres of land in
Pasadena, Texas.
During 1997, the Clear Lake Power Plant generated approximately
2,966,250,000 kilowatt-hours of electric energy for sale to TNP, HL&P and HCCG,
and approximately $97.6 million of revenue.
The Clear Lake Power Plant is currently engaged in litigation with TNP (see
Item 3 -- Legal Proceedings).
Gordonsville and Auburndale Power Plants
On October 9, 1997, the Company completed the acquisition of 50% interests
in the Gordonsville Power Plant and the Auburndale Power Plant. The Company
acquired its interest in the Gordonsville Power Plant through the acquisition of
a 50% general partnership interest in Gordonsville Energy, L.P. from Northern
Hydro Limited ("Hydro") for approximately $14.9 million. The other 50% general
partnership interest in Gordonsville Energy, L.P. is owned by affiliates of
Edison Mission Energy, a subsidiary of Edison International Company.
Construction of the Gordonsville Power Plant was financed with non-recourse
project financing totaling $223.0 million maturing on June 1, 2009. The Company
acquired its interest in the Auburndale Power Plant through the acquisition of a
50% general partnership in Auburndale Power Partners, L.P. from Norweb Power
Services (No. 1) Limited ("Norweb") for approximately $27.5 million. The other
50% general partnership interest in Auburndale Power Partners, L.P. is owned by
affiliates of Edison Mission Energy, a subsidiary of Edison International
Company. The construction of the Auburndale Power Plant was financed with a term
loan in the amount of $126.0 million and a final maturity date of December 31,
2012.
Gordonsville Power Plant -- The Gordonsville Power Plant is a 240 megawatt
gas-fired cogeneration facility located near Gordonsville, Virginia. The
Gordonsville Power Plant consists of two General Electric Stag 107EA
combined-cycle combustion turbines, two steam turbines, two heat recovery steam
generators and an air-cooled condenser. The Gordonsville Power Plant commenced
commercial operation in 1994. In 1997, the Gordonsville Power Plant operated at
an average availability of 96.1%.
Electricity generated by the Gordonsville Power Plant is sold to VEPCO
under two 30-year power sales agreements terminating on June 1, 2024, each of
which include payment provisions for capacity and energy. The power sales
agreements provide for firm capacity payments at a price of $128 per kilowatt
year through 2008 and at a price of $102 for years 2009 through 2024. For the
term of the power sales agreements, Gordonsville is paid for firm capacity up to
217.4 megawatts in the summer and up to 287.8 megawatts in the winter. The power
sales agreements contain dispatch provisions, which allow VEPCO to control the
output of the facility.
The Gordonsville Power Plant sells steam to Rapidan Service Authority under
the terms of a steam purchase and sales agreement for treating wastewater, which
expires June 1, 2004. It is necessary for the Gordonsville Power Plant to
provide a certain amount of thermal energy to a host facility in order to
maintain its QF status.
Gordonsville has two separate natural gas supply and transportation
agreements. During the summer period, gas is supplied by Union Pacific Fuels
Inc. under a 15-year agreement expiring June 2009. During the winter period, gas
is supplied by Tejas Power under a 15-year agreement expiring June 2009, subject
to renewal for a period of five years.
The Gordonsville Power Plant is operated by Edison Mission Operations &
Maintenance Inc. ("EMOM"), under an agreement which expires on December 31,
2024. EMOM is paid on a cost-plus basis for all direct labor plus reimbursement
of certain costs, an annual operating fee and an incentive fee based on
performance.
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<PAGE> 11
The Gordonsville Power Plant is located on approximately 16.7 acres near
the town of Gordonsville, Virginia. The site is owned by and is leased from the
town of Gordonsville under a lease agreement, which expires on June 1, 2024.
During 1997, the Gordonsville Power Plant generated approximately
279,000,000 kilowatt-hours of electrical energy and approximately $38.0 million
of revenue.
Auburndale Power Plant -- The Auburndale Power Plant is a 150 megawatt
gas-fired cogeneration facility located near the city of Auburndale, Florida.
The Auburndale Power Plant consists of a single Westinghouse W501D5 combustion
turbine generator, a Mitsubishi steam turbine and a Nooter-Erickson heat
recovery steam generator. The project uses an on-site zero discharge waste water
system. The Auburndale Power Plant commenced commercial operation in July 1994.
In 1997, the Auburndale Power Plant operated at an average availability of
95.0%.
Electricity generated by the Auburndale Power Plant is sold under various
power sales agreements to Florida Power Corporation ("FPC"), Enron Power
Marketing and Sonat Power Marketing. Auburndale sells 131.18 megawatts of
capacity and energy to FPC under three power sales agreements, each terminating
at the end of 2013. The power sales agreements provide for capacity payments on
114 megawatts at a price of $185 per kilowatt year (1998 dollars) escalating at
5.1% per year. On 17 megawatts, capacity payments are based on $231 per kilowatt
year (1998 dollars) escalating at 6.33% per year.
The Auburndale Power Plant sells steam under two steam purchase and sale
agreements. One agreement is with Cutrale Citrus Juices, USA, an affiliate of
Sucocitro Cutrale LTDA, for an original term of 20 years expiring on July 1,
2014. The second agreement is with Todhunter International, Inc., doing business
as Florida Distillers Company, for an original term of 15 years expiring on July
1, 2009. It is necessary for the Auburndale Power Plant to provide a certain
amount of thermal energy to a host facility in order to maintain QF status.
The Auburndale Power Plant has an 18-year fuel supply contract with Citrus
Trading Corporation, a joint venture between Enron and Sonat Inc., for 25,100
million British thermal units ("mmbtu") per day of natural gas. The fuel supply
contract expires in June 2014.
The Auburndale Power Plant is operated by EMOM. EMOM is paid on a cost-plus
basis for all direct labor plus reimbursement of certain costs, an annual
operating fee and an incentive fee based on performance.
The Auburndale Power Plant is located on a 10-acre site near the city of
Auburndale, Florida. The site is owned by Auburndale Power Partners, L.P.
During 1997, the Auburndale Power Plant generated approximately
1,068,574,000 kilowatt-hours of electrical energy and approximately $50.0
million in revenue.
Gas Energy Inc. Power Plants
On December 19, 1997, Calpine completed the acquisition of 100% of the
capital stock of Gas Energy, Inc. ("GEI") and Gas Energy Cogeneration, Inc.
("GECI") from The Brooklyn Union Gas Company("BUG") for an aggregate purchase
price of $100.9 million (referred to as the "GEI Transaction"). GEI and GECI
indirectly own (i) a 50% general partnership interest in the Kennedy
International Airport Power Plant, a 107 megawatt gas-fired cogeneration
facility, (ii) a 50% general partnership interest in the Stony Brook Power
Plant, a 40 megawatt gas-fired cogeneration facility, (iii) a 45% general
partnership interest in the Bethpage Power Plant, a 57 megawatt gas-fired
cogeneration facility, (iv) an 11.36% limited partnership interest in the
Lockport Power Plant, a 184 megawatt gas-fired cogeneration facility, and (v) a
100% interest in three fuel management contracts. On February 5, 1998, the
Company acquired the remaining 55% interest in, and assumed the operations and
maintenance of, the Bethpage Power Plant for approximately $4.6 million.
Kennedy International Airport Power Plant -- The Kennedy International
Airport Power Plant is a 107 megawatt gas-fired cogeneration facility located at
John F. Kennedy International Airport ("JFK Airport") in Queens, New York. The
facility is owned and operated by KIAC Partners ("KIAC"). The Company owns an
indirect 50% general partner interest in KIAC. The remaining 50% general
partnership
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<PAGE> 12
interest in the project is owned by CEA KIA, Inc., an indirect special purpose
subsidiary of Community Energy Alternatives Incorporated ("CEA"), which is, in
turn, an indirect wholly-owned subsidiary of Public Service Enterprise Group
Incorporated ("PSEG"). The Kennedy International Airport Power Plant commenced
commercial operation in February 1995.
The Kennedy International Airport Power Plant consists of two 42.5 megawatt
General Electric LM6000 gas combustion turbine generators, two Deltak heat
recovery steam generators, a 26 megawatt General Electric steam turbine
generator, a renovated and expanded central heating and refrigeration plant, a
renovated and modified thermal distribution system and state-of-the-art
pollution control equipment. In 1997, the Kennedy International Airport Power
Plant operated at an average availability of 97.3%.
KIAC constructed and is operating the Kennedy International Airport Power
Plant pursuant to a lease expiring in November 2015 (the KIAC Lease Agreement).
KIAC is obligated under the lease to pay facility rental in an amount sufficient
to pay principal and interest of the $250 million of Special Port Authority
Bonds which were issued by the Port Authority in June 1996 to refinance the
original financing for the project and to reimburse a portion of the initial
equity investment. The Special Port Authority Bonds mature in 2019.
Electricity and thermal energy generated by the Kennedy International
Airport Power Plant is sold to the Port Authority, and incremental electric
power is sold to Con Ed, NYPA and other utility customers. Electric power and
chilled and hot water generated by the Kennedy International Airport Power Plant
is sold to the Port Authority under an energy purchase agreement which expires
November 2015 and is subject to an automatic four-year extension if the Port
Authority extends its lease at least four years beyond 2015 with New York City
for JFK Airport. Under the energy purchase agreement, the Port Authority is
obligated to purchase the electrical energy output generated by the Kennedy
International Airport Power Plant up to JFK Airport's requirements (subject to a
maximum of 76.3 megawatts). The purchase price for electric power under the
agreement is the prevailing rate the Port Authority would have paid to NYPA for
electric service if the project were not serving JFK Airport, plus a surcharge
of up to 5%. Under the agreement, the Port Authority is also obligated to
purchase the central terminal tenants' requirements for heating and air
conditioning at JFK Airport.
The Port Authority has a minimum thermal take requirement in an amount
sufficient to maintain the Kennedy International Airport Power Plant's QF
status. It is necessary for the Kennedy International Airport Power Plant to
provide a certain amount of thermal energy to a host facility in order to
maintain its QF status.
The natural gas requirements of the Kennedy International Airport Power
Plant are supplied by Amerada Hess Corporation under a long-term contract in
effect through November 30, 2015. Fuel is transported to the Kennedy
International Airport Power Plant under two interstate transportation contracts
with Energy Development Corporation ("EDC") and EnMark Gas Corp. ("EnMark"). The
EDC contract is effective through November 2015, with a five-year extension
option. The EnMark gas services agreement provides for transportation through
November 2010, subject to renewal at the option of KIAC, for one-year intervals,
for up to 10 years. Local transportation is provided by BUG under a
transportation services agreement, which agreement expires in January 2019,
extendible on a year-to-year basis thereafter. Fuel management and
administration services are provided by Idlewild Fuel Management Corp. ("IFM"),
a wholly-owned subsidiary of the Company, under a long-term fuel management
contract. The agreement is in effect through January 2015.
The Kennedy International Airport Power Plant is operated by CEA Kennedy
Operators, Inc., under a long-term agreement pursuant to which the operator is
reimbursed for certain costs and is entitled to a fixed fee and an incentive
payment based on performance. The agreement expires the earlier of February 2020
or the date of the expiration of the KIAC Lease Agreement.
The Kennedy International Airport Power Plant is located on a seven-acre
site within the JFK Airport. KIAC subleases the land on which the facility is
located from the Port Authority for $100,000 annually under a 20-year site lease
expiring November 30, 2015, subject to extension.
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For 1997, the Kennedy International Airport Power Plant generated
approximately 398,868,000 kilowatt-hours of electrical energy, 206,400 mmbtu of
chilled water and 197,500 mmbtu of hot water for sale to the Port Authority, and
generated approximately $46.3 million in revenue.
Stony Brook Power Plant -- The Stony Brook Power Plant is a 40 megawatt
gas-fired cogeneration facility located on the campus of the State University of
New York ("SUNY") at Stony Brook, New York. The facility is owned by Nissequogue
Cogen Partners ("NCP"). The Company owns an indirect 50% general partner
interest in NCP. The remaining 50% general partner interest is owned by CEA
Stony Brook, Inc., an indirect special purpose subsidiary of CEA, which is, in
turn, an indirect wholly-owned subsidiary of PSEG. The Stony Brook Power Plant
commenced commercial operation in April 1995.
The Stony Brook Power Plant consists of a single General Electric LM6000
aeroderivative combustion turbine generator coupled with a Nooter-Erickson heat
recovery steam generator. In 1997, the Stony Brook Power Plant operated at an
average availability of 94.9%.
On December 15, 1993, NCP entered into a lease agreement for the Stony
Brook Power Plant with the Suffolk Industrial Development Agency (the "Suffolk
IDA") concurrent with the issuance of $79 million of variable rate Industrial
Development Revenue Bonds by the Suffolk IDA to finance the construction of the
facility. The bonds mature in 2010.
Steam and electric power is sold to SUNY under a 20-year energy supply
agreement expiring April 2015. Under the energy supply agreement, SUNY is
required to purchase, and the Stony Brook Power Plant is required to provide,
all of SUNY's electric power and steam requirements up to 36.125 megawatts of
electricity and 280,000 lbs per hr of process steam. The remaining electricity
is sold to LILCo under a long-term agreement. LILCo is obligated to purchase, on
an avoided cost basis, electric power generated by the facility not required by
SUNY. SUNY's purchase price for electric power is equal to 80% of LILCo's 2-MRP
rate, which is its rate for large industrial customers. The purchase price for
steam includes a fixed monthly charge plus a variable charge per pound of steam.
SUNY is required to purchase a minimum of 402,000 klbs per year of steam,
an amount sufficient to maintain QF status of the Stony Brook Power Plant. It is
necessary for the Stony Brook Power Plant to provide a certain amount of thermal
energy to a host facility in order to maintain its QF status.
Natural Gas Clearinghouse, Inc., the successor to Chevron USA, Inc., has
guaranteed a firm supply of up to 12,000 mmbtu per day of gas to NCP for a term
of 15 years, expiring April 2010, under a supply agreement. The supply agreement
can be extended for two additional terms of five years each. Fuel management
services are provided by Stony Brook Fuel Management Corp. ("SBFM"), a
wholly-owned subsidiary of the Company, under a long-term fuel management
contract entered into on December 28, 1993. Gas is transported under gas
transportation agreements with New Jersey Natural Gas Company and LILCo under
agreements that expire in December 2010 and March 2015, respectively.
The Stony Brook Power Plant is operated by CEA Stonybrook Operators, Inc.,
an indirect wholly-owned subsidiary of CEA, under a long-term operations and
maintenance agreement expiring the earlier of either the termination of the site
permit or April 2023.
The Stony Brook Power Plant is located on two acres of leased land within
the SUNY campus in Stony Brook, New York. NCP leases the site, including all
permanent facilities constructed on the site, under a site permit agreement for
a term equivalent to that of the energy supply agreement.
For 1997, the Stony Brook Power Plant generated approximately 305,954,000
kilowatt-hours of electrical energy and 1,117,000 klbs of steam for sale to SUNY
and LILCo, and generated approximately $32.8 million in revenue.
Bethpage Power Plant -- The Bethpage Power Plant is a 57 megawatt gas-fired
cogeneration facility located adjacent to a Northrup Grumman Corporation
("Grummann") facility in Bethpage, New York. The Bethpage Power Plant commenced
commercial operation in August 1989.
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The Bethpage Power Plant consists of two General Electric LM2500
aeroderivative combustion turbines coupled with two Hollandaise Construction
Group heat recovery steam generators and a General Electric steam turbine. Since
start-up, the Bethpage Power Plant has operated at an average availability of
98%.
The Bethpage Power Plant was originally financed with a $54.5 million loan
maturing on March 31, 2004.
Electricity and steam generated by the Bethpage Power Plant are sold to
Grumman under an energy purchase agreement expiring August 2004. Under the
energy purchase agreement, the Bethpage Power Plant provides Grumman up to 30
megawatts of electric power and Grumman is obligated to purchase a minimum of
175,000 megawatt hours per year from the facility; provided, however, that
Grumman may elect to purchase less than 175,000 megawatts per year, subject to a
minimum of 75,000 megawatts per year, upon payment of a demand charge of $0.03
per kilowatt hour on the difference between 175,000 megawatts and the amount
purchased. The purchase price for electric power under the Grumman energy
purchase agreement is 82.5% of LILCo's 2-MRP rate for large industrial
consumers. Excess electricity is sold to LILCo under a 15-year generation
agreement expiring on the same date. LILCo is required to purchase all the
electric power not consumed by Grumman. LILCo's purchase price is equal to the
greater of LILCo's SC-11 capacity and energy buyback tariff rate or $0.06
per-kilowatt hour, subject in either case to a 6.0% discount.
Grumman is also obligated to purchase a minimum of 158,000 klbs of steam
per year from the Bethpage Power Plant. Grumman has an obligation to purchase a
minimum quantity of steam to maintain the QF status of the Bethpage Power Plant.
It is necessary for the Bethpage Power Plant to provide a certain amount of
thermal energy to a host facility in order to maintain its QF status.
Gas is supplied by Enron Gas Marketing Inc. ("EGM") under a long-term gas
purchase agreement with a term extending through 2004. Fuel management and
administration services are provided by Bethpage Fuel Management Inc. ("BFM"), a
wholly-owned subsidiary of the Company, under a 15-year fuel management
agreement expiring in 2004. Gas is transported under a gas services contract
with New Jersey Natural Energy ("NJNE") and a gas transportation agreement with
LILCo for local gas transportation service from the LILCo city gate to the
plant.
The Bethpage Power Plant is currently operated and maintained by General
Electric. The Company will assume operation and maintenance of the Bethpage
Power Plant no later than April 6, 1998.
The Bethpage Power Plant is located on a three-acre site adjacent to the
Grumman facility. The Company currently leases the site from Grumman, but has
entered into an agreement to purchase the site.
For 1997, the Bethpage Power Plant generated approximately 459,022,000
kilowatt-hours of electrical energy for sale to Grumman and LILCo and
approximately $34.8 million in revenue.
Lockport Power Plant -- The Lockport Power Plant is a 184 megawatt
gas-fired cogeneration facility located in Lockport, New York. The facility is
owned and operated by Lockport Energy Associates, L.P. ("LEA"). The Company owns
an indirect 11.36% limited partnership interest in LEA. The other limited
partners of LEA are: Lockport Power Cogeneration, LLC, an affiliate of Harbert
Power Corp. (19.30%); Erie Lockport Power Inc., an affiliate of UtiliCorp Power
Services (22.55%); EMPECO III, Inc., an affiliate of Continental Energy
Services, Inc. (22.31%); TPC Lockport, Inc., an affiliate of Tomen Power
Corporation (18.38%); and Lockport Power Cogeneration II, LLC, an affiliate of
Fortistar Capital, Inc. (5.0%). The 1% managing general partner is FCI Lockport
GP, Inc., an affiliate of Fortistar Capital, Inc. Affiliates of GEI, UtiliCorp
Power Services and Tomen Power Corporation also hold, in aggregate, a 0.1%
general partnership interest in LEA. The Lockport Power Plant commenced
commercial operation on December 28, 1992.
The Lockport Power Plant consists of three 41 megawatt General Electric
Frame 6 combustion turbine generators, three supplementary fired Nooter-Erickson
heat recovery steam generators, a General Electric steam turbine generator and
an auxiliary boiler. In 1997, the Lockport Power Plant operated at an average
availability of 97.0%.
The Lockport Power Plant was financed through a $177.6 million term loan
with the Chase Manhattan Bank, N.A., as agent. The loan matures in 2006.
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Electricity and steam is sold to GM under an energy sales agreement for use
at the GM Harrison plant (the "GM Plant"), which is located on a site adjacent
to the Lockport Power Plant. The energy sales agreement expires December 2007.
The energy sales agreement requires LEA to provide all of the GM Plant's steam
needs and a substantial portion of the GM Plant's electric power requirements.
Electricity is also sold to New York State Electricity and Gas Company
("NYSEG") under a power purchase agreement expiring October 2007 (the "NYSEG
Agreement"). NYSEG is required to purchase all of the electric power produced by
the Lockport Power Plant not required by GM. The price for electric power under
the NYSEG Agreement is based on fixed contractual rates for various periods. The
1997 price was 7.69c per kilowatt hour.
GM is also obligated to purchase all of its steam requirements for the GM
Plant in the amount of up to 315,800 lbs per hour from the Lockport Power Plant.
GM is obligated to purchase steam in sufficient quantities from LEA to maintain
its QF status. It is necessary for the Lockport Power Plant to produce a certain
amount of thermal energy to a host facility in order to maintain its QF status.
Natural gas for the Lockport Power Plant is supplied under three gas sales
contracts expiring October 2007 with each of (i) Aquila Energy Marketing
Corporation ("Aquila"), (ii) North American Resource Company ("NARCO"), and
(iii) ProGas Limited ("ProGas"). Tennessee Gas Pipeline Company ("Tennessee
Gas") provides firm transportation for the domestic gas from Aquila and NARCO
under a 20-year gas transportation agreement. The ProGas quantities are
transported from the Canadian border to the site by Tennessee Gas.
The Lockport Power Plant is operated by North American Energy Services
Company, an indirect 50% owned subsidiary of Montana Power Company, under an
operations and maintenance agreement terminating December 2007, with LEA having
the option to renew the term for an additional one-year period.
The Lockport Power Plant is located on a 15-acre site contiguous with the
GM Plant. LEA purchased the site from GM, leased it to the Town of Lockport
which subsequently leased it back to LEA for a term expiring on May 2025.
For 1997, the Lockport Power Plant generated approximately 1,275,233,000
kilowatt hours of electricity and had $119.6 million in revenue.
The Lockport Power Plant is involved in current litigation with NYSEG in
the Federal District Court of New York (see Item 3 -- Legal Proceedings).
Sumas Power Plant
The Sumas cogeneration facility (the "Sumas Power Plant") is a 125 megawatt
gas-fired cogeneration facility located in Sumas, Washington, near the Canadian
border. In 1991, the Company and Sumas Energy, Inc. ("SEI") formed Sumas
Cogeneration Company, L.P. ("Sumas") for the purpose of developing,
constructing, owning and operating the Sumas Power Plant. The Company is the
sole limited partner in Sumas and SEI is the general partner. On September 30,
1997, the partnership agreement governing Sumas was amended changing the
distribution percentages to the partners. As provided by the terms of the
amendment, the Company increased its percentage share of the project's cash flow
from 50% to approximately 70% through June 30, 2001. Thereafter, the Company
will receive 50% of the project's cash flow until a 24.5% pre-tax rate of return
on its original investment is achieved, at which time the Company's equity
interest in the partnership will be reduced to 0.1%. The Sumas Power Plant
commenced commercial operation in April 1993.
The Company managed the engineering, procurement and construction of the
power plant and related facilities of the Sumas Power Plant, including the gas
pipeline. The Sumas Power Plant was constructed by a Washington joint venture
formed by Industrial Power Corporation and Haskell Corporation. The Sumas Power
Plant is composed of an MS 7001EA combined cycle gas turbine manufactured by
General Electric Company, a Vogt heat recovery steam generator, a General
Electric steam turbine and a 3.5-mile gas pipeline. Since start-up in April
1993, the Sumas Power Plant has operated at an average availability of
approximately 97.4%.
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The Sumas Power Plant's $135.0 million construction and gas reserves
acquisition cost was financed through $120.0 million of construction and term
loan financing provided to Sumas and ENCO Gas, Ltd. ("ENCO"), a wholly owned
Canadian subsidiary of Sumas, by The Prudential Insurance Company of America
("Prudential") and Credit Suisse First Boston Corporation ("Credit Suisse"). The
credit facilities originally included term loans of $70.0 million at a combined
fixed interest rate of 10.28% per annum and variable rate loans of $50.0 million
currently based on the LIBOR, which are amortized over a 15-year period ending
in 2008. In September 1997, Sumas borrowed an additional $20.0 million from
Prudential and Credit Suisse.
Electrical energy generated by the Sumas Power Plant is sold to Puget Sound
Power & Light Company ("Puget") under the terms of a 20-year power sales
agreement terminating in 2013. Under the power sales agreement, Puget has agreed
to purchase an annual average of 123 megawatts of electrical energy.
The power sales agreement provides for the sale of electrical energy at a
total price equal to the sum of (i) a fixed price component and (ii) a variable
price component multiplied by an escalation factor for the year in which the
energy is delivered. The schedule of annual fixed average energy prices
(expressed in cents per kilowatt hour) in effect through 2013 under the Sumas
power sales agreement is as follows:
<TABLE>
<CAPTION>
FIXED FIXED FIXED
ENERGY ENERGY ENERGY
YEAR PRICE YEAR PRICE YEAR PRICE
---- ------ ---- ------ ---- ------
<S> <C> <C> <C> <C> <C>
1998................. 3.64c 2004........... 6.33c 2009........... 5.40c
1999................. 3.98c 2005........... 6.45c 2010........... 5.49c
2000................. 4.23c 2006........... 6.57c 2011........... 5.58c
2001................. 6.23c 2007........... 5.23c 2012........... 5.58c
2002................. 6.11c 2008........... 5.31c 2013........... 5.58c
2003................. 6.22c
</TABLE>
The variable price component is set according to a scheduled rate set forth
in the agreement, which in 1997 was 1.02c per kilowatt hour, and escalates
annually by a factor equal to the U.S. Gross National Product Implicit Price
Deflator. For 1997, the average price paid by Puget under the power sales
agreement was 4.40c per kilowatt hour. Pursuant to the power sales agreement,
Puget may displace the production of the Sumas Power Plant when the cost of
Puget's replacement power is less than the Sumas Power Plant's incremental power
generation costs. Thirty-five percent of the savings to Puget under this
displacement provision are shared with the Sumas Power Plant.
In addition to the sale of electricity to Puget, pursuant to a long-term
steam supply and dry kiln lease agreement, the Sumas Power Plant produces and
sells approximately 23,000 lbs per hour of low pressure steam to an adjacent
lumber-drying facility owned by Sumas, which has been leased to and is operated
by Socco, Inc. ("Socco"), an SEI affiliate. It is necessary to continue to
operate the dry kiln facility in order to maintain the Sumas Power Plant's QF
status.
In connection with the development of the Sumas Power Plant, Canadian
natural gas reserves located primarily in northeastern British Columbia, Canada
were acquired by Sumas through its wholly owned subsidiary, ENCO. The gas
reserves owned by ENCO totaled approximately 105 billion cubic feet as of
January 1, 1998. Firm transportation is contracted for on the Westcoast Energy
Inc. pipeline. Gas is delivered to Huntington, British Columbia, where it is
transferred into Sumas' own pipeline for transportation to the plant. ENCO is
currently supplying approximately 12,900 mmbtu per day to the Sumas Power Plant.
The remaining 12,100 mmbtu per day requirement is being supplied under a
one-year contract with West Coast Gas Services, Inc.
The Company operates and maintains the Sumas Power Plant under an operating
and maintenance agreement pursuant to which the Company is reimbursed for
certain costs and is entitled to a fixed annual fee and an incentive payment
based on project performance. This agreement has an initial term of ten years
expiring in April 2003 and provides for extensions.
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The Sumas Power Plant is located on 13.5 acres located in Sumas,
Washington, which are leased from the Port of Bellingham under the terms of a
23.5-year lease expiring in 2014, subject to renewal. The lease provides for
rental payments according to a fixed schedule.
During 1997, the Sumas Power Plant generated approximately 439,370,000
kilowatt hours of electrical energy and approximately $40.8 million of total
revenue. In 1997, the Company recognized income of approximately $8.6 million in
accordance with the terms of the Sumas partnership agreement, and recorded
revenue of $2.1 million for services performed under the operating and
maintenance agreement.
King City Power Plant
The King City cogeneration facility (the "King City Power Plant") is a 120
megawatt gas-fired combined-cycle facility located in King City, California. In
April 1996, the Company entered into a long-term operating lease for this
facility with BAF Energy ("BAF"). Under the terms of the operating lease, the
Company makes semi-annual lease payments to BAF, a portion of which is supported
by a collateral fund owned by the Company. The collateral consists of a
portfolio of investment grade and U.S. Treasury Securities that mature serially
in amounts equal to a portion of the lease payments.
The power plant consists of a General Electric Frame 7 Model EA combustion
turbine generator, a Nooter-Erickson heat recovery steam generator, an ASEA
Brown Boveri ("ABB") steam turbine generator and two Nebraska Boiler auxiliary
boilers. The King City Power Plant commenced commercial operation in 1989. Since
April 1996, the King City Power Plant has operated at an average availability of
93.4%.
Electricity generated by the King City Power Plant is sold to PG&E under a
30-year power sales agreement terminating in 2019. The power sales agreement
contains payment provisions for capacity and energy. The power sales agreement
provides for a firm capacity payment of $184 per kilowatt year for 111 megawatts
for the term of the agreement so long as the King City Power Plant delivers 80%
of the firm capacity during designated periods of the year. Additional capacity
payments are received for as-delivered capacity in excess of 111 megawatts
delivered during peak and partial peak hours. The as-delivered capacity price is
$188 per kilowatt year for 1998. Thereafter, the payment for as-delivered
capacity will be the greater of $188 per kilowatt year or PG&E's then current
as-delivered capacity rate. From January 1, 1998 through April 30, 1998,
payments for electrical energy produced are based on 100% of the interim
short-run avoided cost ("SRAC"), which is calculated pursuant to the methodology
approved by the CPUC on December 9, 1996. Following the commencement of
operations of the independent power exchange (currently scheduled for April 1,
1998), payments for electrical energy produced will be based on the energy
clearing price of the independent power exchange (referred to herein as the
"Power Exchange Price"). From May 1, 1998 through December 31, 1998, payments
for electrical energy are based on 80% of SRAC (or the Power Exchange Price,
when available) and 20% at fixed prices. The fixed average energy price in
effect for 1998 under the King City power sales agreement is 13.14c per kilowatt
hour. Thereafter, PG&E is required to pay for electrical energy actually
delivered at SRAC (or the Power Exchange Price, when available). During 1997,
SRAC averaged approximately 2.94c per kilowatt hour.
Through April 28, 1999, the power sales agreement allows for dispatchable
operation, which gives PG&E the right to curtail the number of hours per year
that the King City Power Plant operates. PG&E has an option to extend its
curtailment rights for two additional one-year terms. If PG&E exercises the
curtailment extension option, it will be required to pay an additional 0.7c per
kilowatt hour for all energy delivered from the King City Power Plant.
In addition to the sale of electricity to PG&E, the King City Power Plant
produces and sells thermal energy to a thermal host, Basic Vegetable Products,
Inc. ("BVP"), an affiliate of BAF, under a long-term contract coterminous with
the power sales agreement. It is necessary to continue to operate the host
facility in order to maintain the King City Power Plant's QF status. The BVP
facility was built in 1957 and processes between 30% and 40% of the dehydrated
onion and garlic production in the United States.
Natural gas for the King City Power Plant is supplied by Calpine Fuels
Corporation ("Calpine Fuels"), a wholly-owned subsidiary of the Company, which
purchases gas under short-term gas supply agreements.
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Natural gas is transported under a firm transportation agreement, expiring on
March 1, 1999, via a 38-mile pipeline owned and operated by PG&E.
Fee title to the premises is owned by Basic American, Inc., which has
leased the premises to an affiliate of BAF for a term equivalent to the term of
the power sales agreement for the King City Power Plant. The Company is
subleasing the premises, together with certain easements, from such affiliate of
BAF pursuant to a ground sublease for approximately 15 acres.
During 1997, the King City Power Plant generated approximately 424,879,000
kilowatt hours of electrical energy and approximately $45.8 million of total
revenue.
Gilroy Power Plant
On August 29, 1996, the Company acquired the Gilroy cogeneration facility
(the "Gilroy Power Plant"), a 120 megawatt gas-fired facility located in Gilroy,
California. The Company purchased the Gilroy Power Plant for $125.0 million plus
certain contingent consideration, which the Company currently estimates will be
approximately $24.1 million, of which $12.5 million has been paid as of December
31, 1997.
The acquisition of the Gilroy Power Plant was originally financed utilizing
non-recourse project financing in the aggregate amount of $116.0 million. Such
loan consists of a 15-year tranche in the amount of $81.0 million and an 18-year
tranche in the amount of $35.0 million and bears interest at fixed and floating
rates.
The Gilroy Power Plant consists of a General Electric Frame 7 Model EA
combustion turbine generator, an AEG-KANIS steam turbine, a Henry Vogt heat
recovery steam generator, two auxiliary boilers and an inlet chiller using a
Henry Vogt ice machine. The Gilroy Power Plant commenced commercial operation in
March 1988. Since its acquisition by the Company in August 1996, the Gilroy
Power Plant has operated at an average availability of 98.6%.
Electricity generated by the Gilroy Power Plant is sold to PG&E under an
original 30-year power sales agreement terminating in 2018. The power sales
agreement contains payment provisions for capacity and energy. The power sales
agreement provides for a firm capacity payment of $172 per kilowatt year for 120
megawatts for the term of the agreement so long as the Gilroy Power Plant
delivers 80% of the firm capacity during designated periods of the year.
Additional capacity payments are received for as-delivered capacity in excess of
120 megawatts delivered at the greater of $188 per kilowatt year or PG&E's then
current as-delivered capacity rate. In addition, through 1998 the power sales
agreement provides for payments for electrical energy actually delivered at a
price based on the SRAC (or the Power Exchange Price, when available) less
$.00132 per kilowatt hour. Thereafter, PG&E is required to pay for electrical
energy actually delivered at SRAC (or the Power Exchange Price, when available).
During 1997, SRAC averaged approximately 2.94c per kilowatt hour.
Through December 31, 1998, the power sales agreement allows for
dispatchable operation, which gives PG&E the right to curtail the number of
hours per year that the Gilroy Power Plant operates.
In addition to the sale of electricity to PG&E, the Gilroy Power Plant
produces and sells thermal energy to a thermal host, Gilroy Foods, Inc. ("Gilroy
Foods"), under a long-term contract that is coterminous with the power sales
agreement. Gilroy Foods is a recognized leader in the production of dehydrated
onions and garlic. Simultaneously with the acquisition by the Company of the
Gilroy Power Plant, Gilroy Foods was acquired by ConAgra, Inc., an international
food company. It is necessary to continue to operate the host facility in order
to maintain the Gilroy Power Plant's QF status.
Natural gas for the Gilroy Power Plant is supplied by Calpine Fuels, which
purchases gas under short-term gas supply agreements. Natural gas is transported
under a firm transportation agreement with PG&E, expiring on March 1, 1999.
The Gilroy Power Plant is located on approximately five acres of land which
are leased to the Company by Gilroy Foods. The lease term runs concurrent with
the term of the power sales agreement.
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During 1997, the Gilroy Power Plant generated approximately 485,625,000,
kilowatt hours of electrical energy for sale to PG&E and approximately $40.1
million in revenue.
Greenleaf 1 and 2 Power Plants
On April 21, 1995, Calpine completed the acquisition of the Greenleaf 1 and
2 cogeneration facilities (the "Greenleaf 1 and 2 Power Plants") for an adjusted
purchase price of $81.5 million.
On June 30, 1995, Calpine refinanced the existing debt on the Greenleaf 1
and 2 Power Plants by borrowing $76.0 million from Sumitomo Bank. The
non-recourse project financing with Sumitomo Bank is divided into two tranches,
a $60.0 million fixed rate loan facility which bears interest on the unpaid
principal at a fixed rate of 7.415% per annum, with amortization of principal
based on a fixed schedule through June 30, 2005, and a $16.0 million floating
rate loan facility which bears interest based on LIBOR plus an applicable
margin, with the amortization of principal based on a fixed schedule through
December 31, 2010.
The Company is currently negotiating to enter into a sale leaseback of the
Greenleaf 1 and 2 Power Plants. Pursuant to the sale leaseback, the Company
anticipates that the Greenleaf 1 and 2 Power Plants would be sold to an
equipment leasing finance company and the Company would enter into a 15-year
operating lease for the plants. The Company anticipates completing the sale
leaseback in the second quarter of 1998. There can be no assurance that the
Company will successfully complete the sale leaseback.
The Greenleaf 1 and 2 Power Plants have a combined natural gas requirement
of approximately 22,000 mmbtu per day. Natural gas for the Greenleaf 1 and 2
Power Plants is supplied pursuant to a gas sales agreement with Calpine Gas
Company, a wholly-owned subsidiary of the Company, expiring on the termination
of the power sales agreements for the Greenleaf 1 and 2 Power Plants.
Supplemental gas is supplied by Calpine Fuels, which purchases gas under
short-term gas supply agreements. Natural gas is transported under a firm
transportation agreement with PG&E, expiring on March 1, 1999.
Greenleaf 1 Power Plant -- The Greenleaf 1 cogeneration facility (the
"Greenleaf 1 Power Plant") is a 49.5 megawatt gas-fired cogeneration facility
located near Yuba City, California. The Greenleaf 1 Power Plant includes an
LM5000 gas turbine manufactured by General Electric, a Vogt heat recovery steam
generator and a condensing General Electric steam turbine. The Greenleaf 1 Power
Plant commenced commercial operation in March 1989. Since its acquisition by the
Company in April 1995, the Greenleaf 1 Power Plant has operated at an average
availability of approximately 91.6%.
Electricity generated by the Greenleaf 1 Power Plant is sold to PG&E under
a 30-year power sales agreement terminating in 2019 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term
of the agreement, so long as the Greenleaf 1 Power Plant delivers 80% of its
firm capacity during certain designated periods of the year, and an as-delivered
capacity payment for an additional 0.3 megawatts of capacity at $188 per
kilowatt year for 1998. Thereafter, the payment for as-delivered capacity will
be the greater of $188 per kilowatt year or PG&E's then current as-delivered
capacity rate. In addition, the power sales agreement provides for payments for
up to 49.5 megawatts of electrical energy actually delivered at SRAC (or the
Power Exchange Price, when available). During 1997, SRAC averaged approximately
2.94c per kilowatt hour.
In accordance with the power sales agreement, PG&E is entitled to curtail
the Greenleaf 1 Power Plant during hydro-spill periods, or during periods of
negative avoided costs. During 1997, the Greenleaf 1 Power Plant did not
experience curtailment.
In addition to the sale of electricity to PG&E, the Greenleaf 1 Power Plant
sells thermal energy, in the form of hot exhaust to dry wood waste, to a thermal
host which is owned and operated by the Company. It is necessary to continue to
operate the host facility in order to maintain the Greenleaf 1 Power Plant's QF
status.
The Greenleaf 1 Power Plant is located on 77 acres owned by the Company
near Yuba City, California.
For 1997, the Greenleaf 1 Power Plant generated approximately 255,161,000
kilowatt hours of electrical energy for sale to PG&E and approximately $15.9
million in revenue.
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Greenleaf 2 Power Plant -- The Greenleaf 2 cogeneration facility (the
"Greenleaf 2 Power Plant") is a 49.5 megawatt gas-fired cogeneration facility
located near Yuba City, California. The Greenleaf 2 Power Plant includes a STIG
LM5000 gas turbine manufactured by General Electric and a Deltak heat recovery
steam generator. The Greenleaf 2 Power Plant commenced commercial operation in
December 1989. Since its acquisition by the Company in April 1995, the Greenleaf
2 Power Plant has operated at an average availability of approximately 95.9%.
Electricity generated by the Greenleaf 2 Power Plant is sold to PG&E under
a 30-year power sales agreement terminating in 2019 which includes payment
provisions for capacity and energy. The power sales agreement provides for a
firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term
of the agreement, so long as the Greenleaf 2 Power Plant delivers 80% of its
firm capacity during certain designated periods of the year, and an as-delivered
capacity payment for an additional 0.3 megawatts of capacity at $188 per
kilowatt year through 1998. Thereafter, the payment for as-delivered capacity
will be the greater of $188 per kilowatt year or PG&E's then current
as-delivered capacity rate. In addition, the power sales agreement provides for
payments for up to 49.5 megawatts of electrical energy actually delivered at
SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged
approximately 2.94c per kilowatt hour.
In accordance with the power sales agreement, PG&E is entitled to curtail
the Greenleaf 2 Power Plant during hydro-spill periods or during any period of
negative avoided costs. During 1997, the Greenleaf 2 Power Plant did not
experience curtailment.
In addition to the sale of electricity to PG&E, the Greenleaf 2 Power Plant
sells thermal energy to Sunsweet Growers, Inc. ("Sunsweet") pursuant to a
30-year contract. Sunsweet is the largest producer of dried fruit in the United
States. It is necessary to continue to operate the host facility in order to
maintain the status of the Greenleaf 2 Power Plant as a QF.
The Greenleaf 2 Power Plant is located on 2.5 acres of land under a lease
from Sunsweet, which runs concurrent with the power sales agreement.
For 1997, the Greenleaf 2 Power Plant generated approximately 382,041,000
kilowatt hours of electrical energy for sale to PG&E and approximately $20.4
million in revenue.
Agnews Power Plant
The Agnews cogeneration facility (the "Agnews Power Plant") is a 29
megawatt gas-fired, combined-cycle cogeneration facility located on the East
Campus of the state-owned Agnews Developmental Center in San Jose, California.
Calpine holds a 20% ownership interest in GATX Calpine-Agnews, Inc., which is
the sole stockholder of O.L.S. Energy-Agnews, Inc. ("O.L.S. Energy-Agnews").
O.L.S. Energy-Agnews leases the Agnews Power Plant under a sale leaseback
arrangement. The other stockholder of GATX Calpine-Agnews, Inc. is GATX Capital
Corporation ("GATX"), which has an 80% ownership interest. In connection with
the sale leaseback arrangement, Calpine has agreed to reimburse GATX for its
proportionate share of certain payments that may be made by GATX with respect to
the Agnews Power Plant. The Company and GATX managed the development and
financing of the Agnews Power Plant, which commenced commercial operations in
December 1990.
The Company managed the engineering, construction and start-up of the
Agnews Power Plant. The construction work was performed by Power Systems
Engineering, Inc. under a turnkey contract. The power plant consists of an
LM2500 aeroderivative gas turbine manufactured by General Electric, a Deltak
unfired heat recovery steam generator and a Shin Nippon steam turbine-generator.
Since start-up, the Agnews Power Plant has operated at an average availability
of approximately 97.2%.
The total cost of the Agnews Power Plant was approximately $39.0 million.
The construction financing was provided by Credit Suisse in the amount of $28.0
million. After the commencement of commercial operation, the power plant was
sold to Nynex Credit Corporation under a sale leaseback arrangement with O.L.S.
Energy-Agnews. Under the sale leaseback, O.L.S. Energy-Agnews has entered into a
22-year lease,
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commencing March 1991, providing for the payment of a fixed base rental, renewal
options and a purchase option at fair market value at the termination of the
lease.
Electricity generated by the Agnews Power Plant is sold to PG&E under a
30-year power sales agreement terminating in 2021 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
payment of $196 per kilowatt year for 24 megawatts of firm capacity for the term
of the agreement, so long as the Agnews Power Plant delivers at least 80% of its
firm capacity of 24 megawatts during certain designated periods of the year, and
an as-delivered capacity payment for an additional 4 megawatts of capacity at
$188 per kilowatt year for 1998. Thereafter, the payment for as-delivered
capacity will be the greater of $188 per kilowatt year or PG&E's then current
as-delivered capacity rate. In addition, the power sales agreement provides for
payments for up to 32 megawatts of electrical energy actually delivered at a
price equal to (i) through 1998, the product of PG&E's fixed incremental energy
rate and PG&E's utility electric generation gas cost, and (ii) thereafter, SRAC
(or the Power Exchange Price, when available). During 1997, SRAC averaged
approximately 2.94c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1997, PG&E curtailed the energy purchased
under the power sales agreement by 989 hours.
In addition to the sale of electricity to PG&E, the Agnews Power Plant
produces and sells electricity and approximately 7,000 pounds per hour of steam
to the Agnews Developmental Center pursuant to a 30-year energy service
agreement. The energy service agreement provides that the State of California
will purchase from the Agnews Power Plant all of its requirements for steam (up
to a specified maximum) and for electricity for the East Campus of the Agnews
Developmental Center for the term of the agreement. Steam sales are priced at
the cost of production for the Agnews Developmental Center. Electricity sales
are priced at the rates that would otherwise be paid to PG&E by the Agnews
Developmental Center. The State of California is required to utilize the minimum
amount of steam required to maintain the Agnews Power Plant's QF status.
The supply of natural gas for the Agnews Power Plant is currently provided
under a month-to-month full requirements fuel supply agreement between O.L.S.
Energy-Agnews and Amoco Energy Trading Corporation. Natural gas is transported
under a firm gas transportation agreement with PG&E, expiring March 1, 1999.
The Agnews Power Plant is operated by the Company under an operating and
maintenance agreement pursuant to which the Company is reimbursed for certain
costs and is entitled to a fixed annual fee and an incentive payment based on
performance. This agreement expires on January 7, 2003.
The Agnews Power Plant is located on 1.4 acres of land leased from the
Agnews Development Center under the terms of a 30-year lease that expires in
2021. This lease provides for rental payments to the State of California on a
fixed payment basis until January 1, 1999, and thereafter based on the gross
revenues derived from sales of electricity by the Agnews Power Plant, as well as
a purchase option at fair market value.
During 1997, the Agnews Power Plant generated approximately 219,120,000
kilowatt hours of electrical energy and total revenue of $14.9 million. In 1997,
the Company recognized a gain of approximately $17,000 as a result of the
Company's 20% ownership interest and recorded revenue of $1.7 million for
services performed under the operating and maintenance agreement.
Watsonville Power Plant
The Watsonville cogeneration facility (the "Watsonville Power Plant") is a
28.5 megawatt gas-fire cogeneration facility located in Watsonville, California.
On June 29, 1995, the Company acquired the operating lease for this facility for
$900,000 from Ford Motor Credit Company. Under the terms of the lease, rent is
payable each month from July through December. The lease terminates on December
29, 2009. The Watsonville Power Plant commenced commercial operation in May
1990. The power plant consists of a General Electric LM2500 gas turbine, a
Deltak heat recovery steam generator and a Shin Nippon steam turbine. Since its
acquisition by the Company in June 1995, the Watsonville Power Plant has
operated at an average availability of approximately 97.0%.
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Electricity generated by the Watsonville Power Plant is sold to PG&E under
a 20-year power sales agreement terminating in 2009 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
payment of $178 per kilowatt year for 20.9 megawatts of firm capacity for the
term of the agreement, so long as the Watsonville Power Plant delivers at least
80% of its firm capacity of 20.9 megawatts during certain designated periods of
the year, and an as-delivered capacity payment for all megawatts of capacity
delivered above the 20.9 megawatts of firm capacity. The power sales agreement
provides for payments of all electrical energy actually delivered. Through April
2000, 1% of energy will be sold under a fixed energy price and 99% of the energy
will be sold at SRAC (or the Power Exchange Price, when available). For 1998
through 2000, the fixed energy price is 13.90c per kilowatt hours and the
as-delivered capacity price per kilowatt year is $188. Thereafter, PG&E will pay
for energy delivered at SRAC (or the Power Exchange Price, when available) and
will pay for as-delivered capacity at the greater of $188 per kilowatt year or
PG&E's then current as-delivered capacity rate. During 1997, SRAC averaged
approximately 2.94c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
400 hours between January 1 and April 15 and an additional 900 off-peak hours
from November 1 though April 30. From January 1, 1997 through December 31, 1997,
PG&E curtailed energy purchases of 1,300 hours under the power sales agreement.
During 1997, the Watsonville Power Plant produced and sold steam to Farmers
Processing, a food processor. In addition, the Watsonville Power Plant sold
process water produced from its water distillation facility to Farmer's Cold
Storage, Farmer's Processing and Cascade Properties. It is necessary to continue
to operate the host facilities in order to maintain the Watsonville Power
Plant's QF status.
Natural gas for the Watsonville Power Plant is supplied by Calpine Fuels,
which purchases gas under short-term gas supply agreements. Natural gas is
transported under a firm transportation agreement with PG&E, expiring on March
1, 1999.
The Watsonville Power Plant is located on 1.8 acres of land leased from
Norcal Foods under the terms of a 30-year lease expiring in 2010.
For 1997, the Watsonville Power Plant generated approximately 208,325,000
kilowatt hours of electrical energy for sale to PG&E and approximately $12.2
million in revenue.
West Ford Flat Power Plant
The West Ford Flat geothermal facility (the "West Ford Flat Power Plant")
consists of a 27 megawatt geothermal power plant and associated steam fields
located in the eastern portion of The Geysers area of northern California. The
West Ford Flat Power Plant includes a power plant consisting of two turbines
manufactured by Mitsubishi Heavy Industries, Inc. with rotors remanufactured by
ABB Industries, Inc., two generators manufactured by Electric Machinery, Inc.,
nine production wells and various steam leases. The West Ford Flat Power Plant
commenced commercial operation in December 1988. Since start-up, the West Ford
Flat Power Plant has operated at an average availability of approximately 98.5%.
Electricity generated by the West Ford Flat Power Plant is sold to PG&E
under a 20-year power sales agreement terminating in 2008 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
firm capacity payment of $167 per kilowatt year for 27 megawatts of firm
capacity for the term of the agreement, so long as the West Ford Flat Power
Plant delivers 80% of its firm capacity during certain designated periods of the
year. In addition, the power sales agreement provides for energy payments for
electricity actually delivered based on a fixed price derived from a scheduled
forecast of energy prices over the initial ten-year term of the agreement ending
December 1998. The fixed average energy price for 1998 is 13.83c per kilowatt
hour under the West Ford Flat power sales agreement. Thereafter, PG&E is
required to pay for electrical energy actually delivered at SRAC (or the Power
Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c
per kilowatt hour.
The power sales agreement provides that, under certain circumstances, PG&E
may curtail energy deliveries. During 1997, PG&E curtailed the energy purchased
under this agreement by 304 hours. Due to an
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amendment to the power sales agreement in April 1997, the Company currently does
not expect curtailment by PG&E during the remainder of the agreement.
The Company believes that the geothermal reserves that supply energy for
use by the West Ford Flat Power Plant will be sufficient to earn substantially
all of the capacity payments for the remaining term of the power sales agreement
due principally to low projected decline rates, limited development in adjacent
areas and the substantial productive acreage dedicated to the West Ford Flat
Power Plant.
The West Ford Flat Power Plant is located on 267 acres of leased land
located in The Geysers.
During 1997, the West Ford Flat Power Plant generated approximately
213,206,000 kilowatt hours of electrical energy for sale to PG&E and
approximately $35.4 million of revenue.
Bear Canyon Power Plant
The Bear Canyon facility (the "Bear Canyon Power Plant") consists of a 20
megawatt geothermal power plant and associated steam fields located in the
eastern portion of The Geysers area of northern California, two miles south of
the West Ford Flat Power Plant. The Bear Canyon Power Plant includes a power
plant consisting of two turbine generators manufactured by Mitsubishi Heavy
Industries, Inc. with rotors remanufactured by ABB Industries, Inc., as well as
nine production wells, an injection well and steam reserves. The Bear Canyon
Power Plant commenced commercial operation in October 1988. Since start-up, the
Bear Canyon Power Plant has operated at an average availability of approximately
98.2%.
Electricity generated by the Bear Canyon Power Plant is sold to PG&E under
two 10 megawatt, 20-year power sales agreements terminating in 2008 which
contain payment provisions for capacity and energy. One of the power sales
agreements provides for a firm capacity payment of $156 per kilowatt year on
four megawatts for the term of the agreement, so long as the Bear Canyon Power
Plant delivers 80% of its firm capacity during certain designated periods of the
year, and an as-delivered capacity payment for the additional six megawatts of
capacity. The other agreement provides for an as-delivered capacity payment for
the entire 10 megawatts. Both agreements provide for energy payments for
electricity actually delivered based on a fixed price basis through the initial
ten-year term of the agreement ending September 1998. The energy price is 13.83c
per kilowatt hour until September 1998 and, thereafter, PG&E will pay for energy
delivered at SRAC (or the Power Exchange Price, when available). During 1997,
SRAC averaged approximately 2.94c per kilowatt hour. The as-delivered capacity
price is $188 per kilowatt year through 1998, and, thereafter, is the greater of
$188 per kilowatt year or PG&E's then current as-delivered capacity rate.
The power sales agreement provides that, under certain circumstances, PG&E
may curtail energy deliveries. During 1997, PG&E curtailed the energy purchased
under this agreement by 304 hours. Due to an amendment to the power sales
agreement in April 1997, the Company currently does not expect curtailment by
PG&E during the remainder of the agreement.
The Company believes that the geothermal reserves for the Bear Canyon Power
Plant will be sufficient to earn substantially all of the capacity payments for
the remaining term of the power sales agreements due principally to high
reservoir pressures, low projected decline rates, limited development in
adjacent areas and the substantial productive acreage dedicated to the Bear
Canyon Power Plant.
The Bear Canyon Power Plant is located on 284 acres of land located in The
Geysers covered by two leases: one with the State of California and the other
with a private landowner.
During 1997, the Bear Canyon Power Plant generated approximately
168,285,000 kilowatt hours of electrical energy and approximately $25.3 million
of revenue.
Aidlin Power Plant
The Aidlin geothermal facility (the "Aidlin Power Plant") consists of a 20
megawatt geothermal power plant and associated steam fields located in the
western portion of The Geysers area of northern California. The Company holds an
indirect 5% ownership interest in the Aidlin Power Plant. The Company's
ownership interest is held in the form of a 10% general partnership interest in
a limited partnership (the "Aidlin
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Partnership"), which in turn owns a 50% ownership interest, as both a limited
and general partner, in Geothermal Energy Partners Ltd. ("GEP"), a limited
partnership which is the owner of the Aidlin Power Plant. MetLife Capital
Corporation owns the remaining 90% interest in the Aidlin Partnership as a
limited partner. The remaining 50% of GEP is owned by subsidiaries of Mission
Energy Company and Sumitomo Corporation. The Aidlin Power Plant commenced
commercial operation in May 1989.
The Aidlin Power Plant includes a power plant consisting of two turbine and
generator sets manufactured by Fuji Electric and ABB Industries, Inc., as well
as seven production wells and two injection wells. Since start-up, the Aidlin
Power Plant has operated at an average availability of approximately 98.9%.
The construction of the Aidlin Power Plant was financed with a $59.4
million term loan provided by Prudential, which bears interest at a fixed rate
of 10.48% per annum and matures on June 30, 2008 according to a specified
amortization schedule.
Electricity generated by the Aidlin Power Plant is sold to PG&E under two
10 megawatt, 20-year power sales agreements terminating in 2009 which contain
payment provisions for capacity and energy. The power sales agreements provide
for an aggregate firm capacity payment for 17 megawatts of $167 per kilowatt
year for the term of the agreements, so long as the Aidlin Power Plant delivers
80% of its capacity during certain designated periods of the year. In addition,
the Aidlin power sales agreements provide for energy payments for 20 megawatts
based on a schedule of fixed energy prices in effect through 1999 of 13.83c per
kilowatt hour. Thereafter, PG&E is required to pay for electrical energy
actually delivered at SRAC (or the Power Exchange Price, when available). During
1997, SRAC averaged approximately 2.94c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1997, PG&E curtailed the energy purchased
under this agreement by 984 hours.
The Aidlin Power Plant is operated and maintained by the Company under an
operating and maintenance agreement pursuant to which the Company is reimbursed
for certain costs and is entitled to an incentive payment based on project
performance. This agreement expires on December 31, 1999.
The Aidlin Power Plant is located on 713.8 acres of land located in The
Geysers, which is leased by GEP from a private landowner. The lease will remain
in force so long as geothermal steam is produced in commercial quantities.
During 1997, the Aidlin Power Plant generated approximately 172,959,000
kilowatt hours of electrical energy and revenue of $25.0 million. In 1997, the
Company recognized revenue of approximately $455,000 as a result of the
Company's 5% ownership interest and $3.0 million for services performed under
the operating and maintenance agreement.
STEAM FIELDS
Thermal Power Company Steam Fields
The Company acquired Thermal Power Company ("TPC") on September 9, 1994 for
a purchase price of $66.5 million. TPC owns a 25% undivided interest in certain
geothermal steam fields located at The Geysers in northern California (the
"Thermal Power Company Steam Fields"). Union Oil Company of California ("Union
Oil") and NEC own the remaining 75% interest in the steam fields and operates
and maintains the steam fields. The Thermal Power Company Steam Fields include
the leasehold rights to 13,908 acres of steam fields which supply steam to 12
PG&E power plants located in The Geysers and include 238 production wells, 18
injection wells and 55 miles of steam-transporting pipeline. The 12 plants have
a mechanical capacity of 872 megawatts and currently have the capability to
operate at over 560 megawatts. The steam fields commenced commercial operation
in 1960.
The Thermal Power Company Steam Fields produce steam for sale to PG&E under
a long-term steam sales agreement. Under this steam sales agreement, the Company
is paid on the basis of the amount of electricity produced by the power plants
to which steam is supplied. PG&E is obligated to use its best efforts to operate
its power plants to maintain monthly and annual steam field capacity. PG&E is
contractually
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obligated to operate all of the power plants at a minimum of 40% of the field
capacity during any given year, and at 25% of the field capacity in any given
month. The price paid for steam under the steam sales agreement is determined
according to a formula that consists of the average of three indices multiplied
by a fixed price of 1.65c per kilowatt hour. The indices used are the Producer
Price Index for Crude Petroleum, the Producer Price Index for Natural Gas and
the Consumer Price Index ("CPI"). The price of steam under the steam sales
agreement in 1997 was 1.92c per kilowatt hour. The price for 1998 is estimated
to be 1.95c per kilowatt hour. In addition, TPC receives a monthly fee for
effluent disposal and maintenance. During 1997, such monthly fee was $152,000.
In March 1996, TPC, NEC and Union Oil entered into an alternative pricing
agreement with PG&E for any steam produced in excess of 40% of average field
capacity as defined in the steam sales contract. The alternative pricing
agreement is effective through December 31, 2000. Under the alternative pricing
agreement, PG&E has the option to purchase a portion of the steam that PG&E
would likely curtail under the existing steam sales agreement. The price for
this portion of steam will be set by TPC, NEC and Union Oil with the intent that
it be at competitive market prices. TPC, NEC and Union Oil will solely determine
the price and duration of these alternative prices.
The steam sales agreement with PG&E also provides for offset payments,
which constitute a remedy for insufficient steam. The offset payments are
calculated based upon a fixed amortization schedule for all power plants, which
may be adjusted for future capital expenditures, and upon the steam fields'
capacity in megawatts. In accordance with the steam sales agreement, TPC makes
offset payments at a reduced rate until total offsets calculated since July 1,
1991 equal $15.0 million. Accordingly, TPC's share of offsets in 1997 was
$582,000. In approximately 2001, when total offsets may exceed $15.0 million, in
accordance with the agreement TPC's share of offset payments to PG&E would be
approximately 3 1/2 times their current rate (as calculated at the current steam
field capacity).
The steam sales agreement with PG&E terminates two years after the closing
of the last operating power plant. In addition, PG&E may terminate the contract
earlier with a one-year written notice. If PG&E terminates in accordance with
the steam sales agreement, TPC will provide capacity maintenance services for
five years after the termination date, and will retain a right of first refusal
to purchase the PG&E facilities at PG&E's unamortized cost. Alternatively, TPC
may terminate the agreement with a two-year written notice to PG&E. If TPC
terminates, PG&E has the right to take assignment of the Thermal Power Company
Steam Fields' facilities on the date of termination. In that case, TPC would
continue to pay offset payments for three years following the date of
termination. Under the steam sales agreement, PG&E may retire older power plants
upon a minimum of six-months' notice. TPC is unable to predict PG&E's schedule
for the retirement of such power plants, which may change from time to time. If
steam is abandoned (i.e., cannot be transported to the remaining plants), the
abandoned steam may be delivered for use to other PG&E power plants, subject to
existing contract conditions, or to other customers upon closure of a PG&E power
plant.
The Thermal Power Company Steam Fields currently supply steam sufficient to
operate the PG&E power plants at approximately 60% of their combined mechanical
capacity. This percentage reflects a decline in productivity since the
commencement of operations. While it is not possible to accurately predict
long-term steam field productivity, the Company has estimated that the current
annual rate of decline in steam field productivity of the Thermal Power Company
Steam Fields is approximately 8%. The Company expects steam field productivity
to continue to decline in the future. The City of Santa Rosa, California, has
selected a proposal jointly submitted by the Company and Union Oil to construct
a water injection project utilizing tertiary treated wastewater from the City of
Santa Rosa. This project is expected to partially offset the anticipated rate of
decline in steam field productivity. The implementation of this project, if
completed, is subject to certain conditions, including the receipt of state and
federal funding.
PG&E has recently announced its intention to sell all of its power
generating facilities in The Geysers that purchase steam from TPC and the PG&E
Unit 13 and PG&E Unit 16 Steam Fields. The Company cannot predict the impact
that any such sale would have on the Company's results of operations or
financial condition.
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In conjunction with Union Oil and NEC, TPC holds a right of first refusal
to match any sales offer for PG&E's 12 power plants which are served by the
Thermal Power Company Steam Fields. It cannot be determined at this time whether
PG&E will complete the sale of the power plants or whether Union Oil, NEC and
TPC will exercise their right of first refusal. On February 13, 1998, Union Oil,
NEC and TPC filed a protest with the CPUC objecting to certain aspects of PG&E's
application to sell the power plants. In addition, Union Oil, NEC and TPC have
commenced arbitration proceedings with PG&E under the steam sales agreement in a
dispute over the interpretation of contract provisions concerning minimum
operation levels of the power plants.
During 1997, the PG&E power plants produced 3,487,592,000 kilowatt hours of
electrical energy of which the Company's 25% share is 871,898,000 kilowatt hours
for approximately $15.8 million of revenue.
PG&E Unit 13 and Unit 16 Steam Fields
The Company holds the leasehold rights to 1,631 acres of steam fields (the
"PG&E Unit 13 and Unit 16 Steam Fields") that supply steam to PG&E's Unit 13
power plant (the "Unit 13") and PG&E's Unit 16 power plant (the "Unit 16"), all
of which are located in The Geysers. The PG&E Unit 13 Steam Field includes 956
acres, 28 production wells, five injection wells and five miles of pipeline, and
commenced commercial operations in May 1980. The PG&E Unit 16 Steam Field
includes 675 acres, 19 producing wells, two injection wells, and three miles of
pipeline, and commenced commercial operation in October 1985.
The PG&E Unit 13 and Unit 16 Steam Fields produce steam for sale to PG&E
under long-term steam sales agreements. Under the steam sales agreements with
PG&E, the Company is paid for steam on the basis of the amount of electricity
produced by Unit 13 and Unit 16. The price paid for steam under the PG&E Unit 13
and Unit 16 Steam Fields agreements is determined according to a formula that is
essentially a weighted average of PG&E's fossil (oil and gas) fuel price and
PG&E's nuclear fuel price. The price of steam for 1997 was 0.95c per kilowatt
hour. The Company receives an additional 0.05c per kilowatt hour from PG&E for
the disposal of liquid effluents produced at Unit 13 and Unit 16.
During conditions of hydro-spill, PG&E may curtail energy deliveries from
Unit 13 and Unit 16 which would reduce deliveries of steam under this agreement.
Curtailments are primarily the result of a higher degree of precipitation during
the period, which results in higher levels of energy generation by hydroelectric
power facilities that supply electricity for sale by PG&E. In the event of any
such curtailment, the Company's results of operations may be materially
adversely affected. PG&E curtailed approximately 37,371,590 kilowatt hours under
the steam sales agreement during 1997.
The steam sales agreement with PG&E continues in effect for as long as
either Unit 13 or Unit 16 remains in commercial operation for PG&E, which
depends in part on maintaining the productive capacity of the respective steam
fields. However, PG&E may terminate the agreement if the quantity, quality or
purity of the steam is such that the operation of Unit 13 or Unit 16 becomes
economically impractical. No assurance can be given that the operation of either
Unit 13 or Unit 16 will not become economically impractical at any time.
The Company is required to supply a sufficient quantity of steam of
specified quality to Unit 16. If an insufficient quantity of steam is delivered,
the Company may be subject to penalty provisions, including suspension of PG&E's
obligation to pay for steam delivered. Specifically, if the Company fails to
deliver to Unit 16 in any calendar month a sufficient quantity of steam adequate
to operate the power plant at or above a capacity factor of 50%, no payment
shall be made for steam delivered to such Unit during such month until the cost
of that Unit has been completely amortized by PG&E.
In order to increase the efficiency of Unit 13 by approximately 20%, the
Company agreed to purchase new rotors for $10.8 million. In exchange, PG&E
agreed to amend the steam sales agreement to remove the penalty provision for a
failure to deliver a sufficient quantity of steam to Unit 13 and to require PG&E
to operate at variable pressure operations which will optimize production at the
PG&E Unit 13 and Unit 16 Steam Fields.
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The PG&E Unit 13 and Unit 16 Steam Fields currently supply steam sufficient
to operate Unit 13 and Unit 16 at approximately 77% of their combined nameplate
capacities. This percentage reflects a decline in the productivity of the PG&E
Unit 13 and Unit 16 Steam Fields since the commencement of operations of Unit 13
and Unit 16. While it is not possible to accurately predict long-term steam
field productivity, the Company has estimated that the annual rate of decline in
steam field productivity of the PG&E Unit 13 and Unit 16 Steam Fields was
approximately 6.0% in 1997. The Company expects steam field productivity to
continue to decline in the future, but at reduced annual rates of decline. The
Company considered these declines in steam field productivity in developing its
original projections for the PG&E Unit 13 and Unit 16 Steam Fields at the time
the Company acquired its initial interest in 1990. The Company plans to
partially offset the expected rate of decline by implementing enhanced water
injection and power plant improvements.
PG&E has recently announced its intention to sell all of its power
generating facilities in The Geysers that purchase steam from Thermal Power
Company and the PG&E Unit 13 and PG&E Unit 16 Steam Fields. The Company cannot
predict the impact that any such sale would have on the Company's results of
operations or financial condition.
The Company has filed a protest with the CPUC challenging certain aspects
of PG&E's application to sell Units 13 and 16. In addition, the Company has
filed an action in state court seeking a declaratory judgment and injunctive
relief to prohibit PG&E from assigning the steam contract to a third party
through its sale of the power plants.
During 1997, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient
steam to permit Unit 13 and Unit 16 to produce approximately 1,295,000,000
kilowatt hours of electrical energy and approximately $13.0 million of revenue.
SMUDGEO #1 Steam Fields
The Company holds the leasehold rights to 394 acres of steam fields that
supply steam to the power plant for the Sacramento Municipal Utility District
("SMUD") SMUDGEO #1 steam fields (the "SMUDGEO #1 Steam Fields"). The SMUD power
plant has a nameplate capacity of 72 megawatts and currently operates at an
output of 50 megawatts. The SMUDGEO #1 Steam Fields include 19 producing wells,
one injection well and two and one half miles of pipeline. Commercial operation
of the SMUD power plant commenced in October 1983.
The steam sales agreement with SMUD provides that SMUD will pay for steam
based upon the quantity of steam delivered to the SMUD power plant. The current
price paid for steam delivered under the steam sales agreement is $1.818 per
thousand pounds of steam, which is adjusted semi-annually based on changes in
the Gross National Product Implicit Price Deflator Index and Producers Price
Index for Fuels, Related Products and Power. SMUD may suspend payments for steam
in any month if the Company is unable to deliver 50% of the steam requirement
until the cost of the plant and related facilities have been completely
amortized by the value of such steam delivered to the plant. The Company
receives an additional 0.15c. per kilowatt hour from SMUD for the disposal of
liquid effluents produced at the SMUDGEO #1 Steam Fields.
The steam sales agreement with SMUD continues until the expiration or
termination of the geothermal lease covering the SMUDGEO #1 Steam Fields, which
continues for so long as steam is produced in commercial quantities. The Company
and SMUD each have the right to terminate the agreement if their respective
operations become economically impractical. In the event that SMUD exercises its
right to terminate, the Company will have no further obligation to deliver steam
to the power plants.
The SMUDGEO #1 Steam Fields currently supply steam sufficient to operate
the SMUD power plant at approximately 69% of its nameplate capacity. This
percentage reflects a decline in the productivity of the SMUDGEO #1 Steam Fields
since commencement of operations.
During 1997, the SMUDGEO #1 Steam Fields produced approximately 6,924,000
thousand pounds of steam and approximately $13.1 million of revenue.
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Cerro Prieto Steam Fields
In 1995, the Company entered into a series of agreements with Constructora
y Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain of Coperlasa's
creditors pursuant to which the Company has agreed to invest up to $20 million
in the Cerro Prieto steam fields (the "Cerro Prieto Steam Fields") located in
Baja California, Mexico. The Cerro Prieto Steam Fields provide geothermal steam
to three geothermal power plants owned and operated by Comision Federal de
Electricidad ("CFE"), the Mexican national utility.
The Company's investment consists of a loan of $18.5 million and a $1.5
million payment for an option to purchase a 29% equity interest in Coperlasa for
$5.8 million.
The $18.5 million loan was made in installments throughout 1995 and 1996,
which provided capital to Coperlasa to fund the drilling of new wells and the
repair of existing wells to meet its performance under the agreement with CFE.
The loan matures in November 1999 and bears interest at an effective rate of
18.9% per annum. The Company is deferring the recognition of income on this loan
until the Cerro Prieto project generates sufficient cash flows available for
distribution to support the collectibility of interest earned.
Pursuant to a technical services agreement, the Company receives fees for
its technical services provided to Coperlasa. In addition, if the Company is
successful in assisting Coperlasa in producing steam at a lower cost, the
Company will receive 30% of the savings, if any.
The Cerro Prieto Steam Fields are located near the city of Mexicali, Baja
California, at the border of Baja California and the State of California. The
Cerro Prieto geothermal resource, which has been commercially produced by CFE
since 1973, provides approximately 70% of Baja California's electricity
requirements since this region is not connected to the Mexican national power
grid.
The steam sales agreement between Coperlasa and CFE was entered into in May
1991. Under this agreement, CFE pays for steam delivered up to 1,600 tons per
hour plus 10%. Payments for the steam delivered are made in Mexican pesos and
are adjusted on a specific unit-of-production basis by a formula that accounts
for the increases in inflation in Mexico and the United States, as well as for
the devaluation of the peso against the U.S. dollar. This agreement has a
termination date of October 2000.
GAS FIELDS
Montis Niger Gas Fields
On January 31, 1997, the Company purchased Montis Niger, Inc. a gas
production and pipeline company operating primarily in the Sacramento Basin in
northern California. On July 25, 1997, Montis Niger, Inc. was renamed Calpine
Gas Company. As of January 1, 1998, Calpine Gas Company had approximately 8.1
billion cubic feet of proven natural gas reserves and approximately 16,094 gross
acres and 15,037 net acres under lease in the Sacramento Basin. In addition,
Calpine Gas Company owns and operates an 80-mile pipeline delivering gas to the
Greenleaf 1 and 2 Power Plants which had been either produced by Calpine Gas
Company or purchased from third parties. Calpine Gas Company currently supplies
approximately 80% of the fuel requirements for the Greenleaf 1 and 2 Power
Plants.
PROJECT DEVELOPMENT AND ACQUISITION
The Company is actively engaged in the development and acquisition of power
generation projects. The Company has historically focused principally on the
development and acquisition of interests in gas-fired and geothermal power
projects, although the Company also considers projects that utilize other power
generation technologies. The Company has significant expertise in a variety of
power generation technologies and has substantial capabilities in each aspect of
the development and acquisition process, including design, engineering,
procurement, construction management, fuel and resource acquisition and
management, financing and operations.
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PROJECT DEVELOPMENT
The development of power generation projects involves numerous elements,
including evaluating and selecting development opportunities, designing and
engineering the project, obtaining power and steam sales agreements, acquiring
necessary land rights, permits and fuel resources, obtaining financing, and
managing construction. The Company intends to focus primarily on development
opportunities where the Company is able to capitalize on its expertise in
implementing an innovative and fully integrated approach to project development
in which the Company controls the entire development process. Utilizing this
approach, the Company believes that it is able to enhance the value of its
projects throughout each stage of development in an effort to maximize its
return on investment.
The Company is pursuing the development of highly efficient, low-cost
merchant power plants that seek to take advantage of inefficiencies in the
electricity market. The Company intends to sell all or a portion of the power
generated by such merchant plants into the competitive market through a
portfolio of short-, medium-and long-term power sales agreements. The Company
expects that these projects will represent a prototype for future merchant plant
developments by the Company. The Company currently plans to develop additional
low-cost, gas-fired facilities in California, Texas, New England and other high
priced power markets.
The development of power generation facilities is subject to substantial
risks. In connection with the development of a power generation facility, the
Company must generally obtain power and/or steam sales agreements, governmental
permits and approvals, fuel supply and transportation agreements, sufficient
equity capital and debt financing, electrical transmission agreements, site
agreements and construction contracts, and there can be no assurance that the
Company will be successful in doing so. In addition, project development is
subject to certain environmental, engineering and construction risks relating to
cost-overruns, delays and performance. Although the Company may attempt to
minimize the financial risks in the development of a project by securing a
favorable long-term power sales agreement, entering into power marketing
transactions, obtaining all required governmental permits and approvals and
arranging adequate financing prior to the commencement of construction, the
development of a power project may require the Company to expend significant
sums for preliminary engineering, permitting and legal and other expenses before
it can be determined whether a project is feasible, economically attractive or
financeable. If the Company were unable to complete the development of a
facility, it would generally not be able to recover its investment in such a
facility. The process for obtaining initial environmental, siting and other
governmental permits and approvals is complicated and lengthy, often taking more
than one year, and is subject to significant uncertainties. As a result of
competition, it may be difficult to obtain a power sales agreement for a
proposed project, and the prices offered in new power sales agreements for both
electric capacity and energy may be less than the prices in prior agreements.
There can be no assurance that the Company will be successful in the development
of power generation facilities in the future.
Pasadena Power Plant
Calpine has entered into a development agreement with Phillips Petroleum
Company ("Phillips") to construct and operate a 240 megawatt, gas-fired
cogeneration project at the Phillips Houston Chemical Complex ("HCC") located in
Pasadena, Texas (the "Pasadena Power Plant"). On December 19, 1996, the Company
entered into an Energy Sales Agreement with Phillips pursuant to which Phillips
will purchase all of the HCC's steam and electricity requirements of
approximately 90 megawatts. It is anticipated that the remainder of available
electricity output will be sold into the competitive market through Calpine's
power sales activities. On December 20, 1996, the Company entered into a credit
agreement with ING U.S. Capital Corporation to provide $151.8 million of
construction loans and $98.6 million of term loan non-recourse project financing
for the Pasadena Power Plant. In accordance with the terms of the agreement,
Calpine contributed $53.1 million in equity to the project. The Company
commenced construction in February 1997, with commercial operation scheduled to
begin in July 1998.
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Dighton and Tiverton Power Plants
In October 1997, Calpine entered into agreements with Energy Management
Inc. ("EMI"), a New England based power developer, to invest in the development
of two merchant power plants in New England, including a 169 megawatt gas-fired
combined-cycle merchant power plant to be located in Dighton, Massachusetts (the
"Dighton Power Plant") and a 265 megawatt gas-fired power plant to be located in
Tiverton, Rhode Island (the "Tiverton Power Plant"). The Company intends to
invest $43.0 million of equity in the development of the Tiverton Power Plant.
In October 1997, the Company invested $16.0 million in the development of the
Dighton Power Plant. This investment, which is structured as subordinated debt,
will provide the Company with a preferred payment stream at a rate of 12.07% per
annum for a period of twenty years from the commercial operation date. The
Dighton Power Plant is being developed by EMI. It is estimated that the
development of the Dighton Power Plant will cost approximately $120.0 million,
which is being financed, in part, with $104.0 million of non-recourse
construction financing. Upon commercial operation, EMI is expected to contribute
$2.0 million of equity and the construction financing will convert to a $102.0
million term loan non-recourse project financing. Construction commenced in the
fourth quarter of 1997 and commercial operation is scheduled to begin in early
1999. Upon completion, the Dighton Power Plant will be operated by EMI and will
sell its output into the New England Power Pool and to wholesale and retail
customers in the northeastern United States.
Pursuant to a letter agreement with EMI providing for an exclusivity period
for negotiations through March 31, 1998, the Company intends to invest up to
$43.0 million of equity in the development of the Tiverton Power Plant. The
Tiverton Power Plant is being developed by EMI. It is estimated that the
development of the Tiverton Power Plant will cost approximately $173.0 million.
Construction is currently scheduled to commence in late 1998 and commercial
operation is scheduled for early 2000. Upon completion, the Tiverton Power Plant
will be operated by EMI and will sell its output in the New England Power Pool
and to wholesale and retail customers in the northeastern United States.
Magic Valley Power Plant
On January 21, 1998, Calpine announced that it had been selected by Magic
Valley Electric Cooperative, Inc., located in South Texas, to begin final
negotiations to supply its electric needs from 2001 through 2021. The Company
expects the electricity will be supplied by a 700 megawatt gas-fired merchant
power plant currently under development by the Company in Edinburg, Texas.
Sutter Power Plant
In February 1997, the Company announced plans to develop a 500 megawatt
gas-fired combined cycle project in Sutter County, in northern California (the
"Sutter Power Plant"). The Sutter Power Plant would be northern California's
first newly constructed merchant power plant. The Sutter Power Plant is expected
to provide electricity to the deregulated California power market commencing in
the year 2000. The Company is currently pursuing regulatory agency permits for
this project. On January 21, 1998, the Company announced that the Sutter Power
Plant has met the California Energy Commission's Data Adequacy requirements in
its Application for Certification.
ACQUISITIONS
The Company will consider the acquisition of an interest in operating
projects as well as projects under development where Calpine would assume
responsibility for completing the development of the project. In the acquisition
of power generation facilities, Calpine generally seeks to acquire an ownership
interest in facilities that offer the Company attractive opportunities for
revenue and earnings growth, that have existing, favorable long-term power sales
agreements with major electric utilities or major users of power (i.e.,
industrial facilities), and that permit the Company to assume sole
responsibility for the operation and maintenance of the facility. In evaluating
and selecting a project for acquisition, the Company considers a variety of
factors, including the type of power generation technology utilized, the
location of the project, the terms of any existing power or thermal energy sales
agreements, gas supply and transportation agreements and wheeling
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agreements, the quantity and quality of any geothermal or other natural resource
involved, and the actual condition of the physical plant. In addition, the
Company assesses the past performance of an operating project and prepares
financial projections to determine the profitability of the project. The Company
generally seeks to obtain a significant equity interest in a project and to
obtain the operation and maintenance contract for that project.
The Company has grown substantially in recent years as a result of
acquisitions of interests in power generation facilities and steam fields. The
Company believes that although the domestic power industry is undergoing
consolidation and that significant acquisition opportunities are available, the
Company is likely to confront significant competition for acquisition
opportunities. In addition, there can be no assurance that the Company will
continue to identify attractive acquisition opportunities at favorable prices
or, to the extent that any opportunities are identified, that the Company will
be able to consummate such acquisitions.
Pittsburg Power Plant
On February 18, 1998, the Company announced that it has entered into
exclusive negotiations for a four month period ending May 31, 1998, with The Dow
Chemical Company ("Dow") to acquire its 70 megawatt gas-fired power plant and a
natural gas pipeline system located adjacent to Dow's chemical plant in
Pittsburg, California. The pipeline delivers low-cost fuel to the plant from
Sacramento Basin gas fields. As part of the transaction, The Company will enter
into long-term agreements with Dow to provide electricity and steam to its
chemical facility and steam to the nearby USS-POSCO Industries steel mill. In
addition, the Company will acquire rights to a site at the Dow chemical facility
suitable for future expansion. The Company expects to complete the acquisition
during the second quarter of 1998.
GOVERNMENT REGULATION
The Company is subject to complex and stringent energy, environmental and
other governmental laws and regulations at the federal, state and local levels
in connection with the development, ownership and operation of its energy
generation facilities. Federal laws and regulations govern transactions by
electrical and gas utility companies, the types of fuel which may be utilized by
an electric generating plant, the type of energy which may be produced by such a
plant and the ownership of a plant. State utility regulatory commissions must
approve the rates and, in some instances, other terms and conditions under which
public utilities purchase electric power from independent producers and sell
retail electric power. Under certain circumstances where specific exemptions are
otherwise unavailable, state utility regulatory commissions may have broad
jurisdiction over non-utility electric power plants. Energy producing projects
also are subject to federal, state and local laws and administrative regulations
which govern the emissions and other substances produced, discharged or disposed
of by a plant and the geographical location, zoning, land use and operation of a
plant. Applicable federal environmental laws typically have both state and local
enforcement and implementation provisions. These environmental laws and
regulations generally require that a wide variety of permits and other approvals
be obtained before the commencement of construction or operation of an energy-
producing facility and that the facility then operate in compliance with such
permits and approvals.
FEDERAL ENERGY REGULATION
PURPA
The enactment of the Public Utility Regulatory Policies Act of 1978, as
amended ("PURPA") and the adoption of regulations thereunder by FERC provided
incentives for the development of cogeneration facilities and small power
production facilities (those utilizing renewable fuels and having a capacity of
less than 80 megawatts).
A domestic electricity generating project must be a QF under FERC
regulations in order to take advantage of certain rate and regulatory incentives
provided by PURPA. PURPA exempts owners of QFs from the Public Utility Holding
Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions
of the Federal Power Act (the "FPA") and, except under certain limited
circumstances, state
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laws concerning rate or financial regulation. These exemptions are important to
the Company and its competitors. The Company believes that each of the
electricity generating projects in which the Company owns an interest currently
meets the requirements under PURPA necessary for QF status. Most of the projects
which the Company is currently planning or developing are also expected to be
QFs.
PURPA provides two primary benefits to QFs. First, QFs generally are
relieved of compliance with extensive federal, state and local regulations that
control the financial structure of an electric generating plant and the prices
and terms on which electricity may be sold by the plant. Second, the FERC's
regulations promulgated under PURPA require that electric utilities purchase
electricity generated by QFs at a price based on the purchasing utility's
"avoided cost," and that the utility sell back-up power to the QF on a non-
discriminatory basis. The term "avoided cost" is defined as the incremental cost
to an electric utility of electric energy or capacity, or both, which, but for
the purchase from QFs, such utility would generate for itself or purchase from
another source. The FERC regulations also permit QFs and utilities to negotiate
agreements for utility purchases of power at rates lower than the utility's
avoided costs. Due to increasing competition for utility contracts, the current
practice is for most power sales agreements to be awarded at a rate below
avoided cost. While public utilities are not explicitly required by PURPA to
enter into long-term power sales agreements, PURPA helped to create a regulatory
environment in which it has been common for long-term agreements to be
negotiated.
In order to be a QF, a cogeneration facility must produce not only
electricity, but also useful thermal energy for use in an industrial or
commercial process for heating or cooling applications in certain proportions to
the facility's total energy output and must meet certain energy efficiency
standards. Finally, a QF (including a geothermal or hydroelectric QF or other
qualifying small power producer) must not be controlled or more than 50% owned
by an electric utility or by most electric utility holding companies, or a
subsidiary of such a utility or holding company or any combination thereof.
The Company endeavors to develop its projects, monitor compliance by the
projects with applicable regulations and choose its customers in a manner which
minimizes the risks of any project losing its QF status. Certain factors
necessary to maintain QF status are, however, subject to the risk of events
outside the Company's control. For example, loss of a thermal energy customer or
failure of a thermal energy customer to take required amounts of thermal energy
from a cogeneration facility that is a QF could cause the facility to fail
requirements regarding the level of useful thermal energy output. Upon the
occurrence of such an event, the Company would seek to replace the thermal
energy customer or find another use for the thermal energy which meets PURPA's
requirements, but no assurance can be given that this would be possible.
If one of the projects in which the Company has an interest should lose its
status as a QF, the project would no longer be entitled to the exemptions from
PUHCA and the FPA. This could trigger certain rights of termination under the
power sales agreement, could subject the project to rate regulation as a public
utility under the FPA and state law and could result in the Company
inadvertently becoming a public utility holding company by owning more than 10%
of the voting securities of, or controlling, a facility that would no longer be
exempt from PUHCA. This could cause all of the Company's remaining projects to
lose their qualifying status, because QFs may not be controlled or more than 50%
owned by such public utility holding companies. Loss of QF status may also
trigger defaults under covenants to maintain QF status in the projects' power
sales agreements, steam sales agreements and financing agreements and result in
termination, penalties or acceleration of indebtedness under such agreements
such that loss of status may be on a retroactive or a prospective basis.
If a project were to lose its QF status, the Company could attempt to avoid
holding company status (and thereby protect the QF status of its other projects)
on a prospective basis by restructuring the project, by changing its voting
interest in the entity owning the non-qualifying project to nonvoting or limited
partnership interests and selling the voting interest to an individual or
company which could tolerate the lack of exemption from PUHCA, or by otherwise
restructuring ownership of the project so as not to become a holding company.
These actions, however, would require approval of the Securities and Exchange
Commission ("SEC") or a no-action letter from the SEC, and would result in a
loss of control over the non-qualifying project, could result in a reduced
financial interest therein and might result in a modification of the Company's
operation and
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maintenance agreement relating to such project. A reduced financial interest
could result in a gain or loss on the sale of the interest in such project, the
removal of the affiliate through which the ownership interest is held from the
consolidated income tax group or the consolidated financial statements of the
Company, or a change in the results of operations of the Company. Loss of QF
status on a retroactive basis could lead to, among other things, fines and
penalties being levied against the Company and its subsidiaries and claims by
utilities for refund of payments previously made.
Under the Energy Policy Act of 1992, if a project can be qualified as an
exempt wholesale generator ("EWG"), it will be exempt from PUHCA even if it does
not qualify as a QF. Therefore, another response to the loss or potential loss
of QF status would be to apply to have the project qualified as an EWG. However,
assuming this changed status would be permissible under the terms of the
applicable power sales agreement, rate approval from FERC and approval of the
utility would be required. In addition, the project would be required to cease
selling electricity to any retail customers (such as the thermal energy
customer) and could become subject to state regulation of sales of thermal
energy.
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at avoided costs. The Company does not know whether such legislation will be
passed or what form it may take. The Company believes that if any such
legislation is passed, it would apply to new projects. As a result, although
such legislation may adversely affect the Company's ability to develop new
projects, the Company believes it would not affect the Company's existing QFs.
There can be no assurance, however, that any legislation passed would not
adversely impact the Company's existing projects.
Public Utility Holding Company Regulation
Under PUHCA, any corporation, partnership or other legal entity which owns
or controls 10% or more of the outstanding voting securities of a "public
utility company" or a company which is a "holding company" for a public utility
company is subject to registration with the SEC and regulation under PUHCA,
unless eligible for an exemption. A holding company of a public utility company
that is subject to registration is required by PUHCA to limit its utility
operations to a single integrated utility system and to divest any other
operations not functionally related to the operation of that utility system.
Approval by the SEC is required for nearly all important financial and business
dealings of the holding company. Under PURPA, most QFs are not public utility
companies under PUHCA.
The Energy Policy Act of 1992, among other things, amends PUHCA to allow
EWGs, under certain circumstances, to own and operate non-QFs without subjecting
those producers to registration or regulation under PUHCA. The expected effect
of such amendments would be to enhance the development of non-QFs which do not
have to meet the fuel, production and ownership requirements of PURPA. The
Company believes that the amendments could benefit the Company by expanding its
ability to own and operate facilities that do not qualify for QF status, but may
also result in increased competition by allowing utilities to develop such
facilities which are not subject to the constraints of PUHCA.
Federal Natural Gas Transportation Regulation
The Company has an ownership interest in and operates ten gas-fired
cogeneration projects. The cost of natural gas is ordinarily the largest expense
(other than debt costs) of a project and is critical to the project's economics.
The risks associated with using natural gas can include the need to arrange
transportation of the gas from great distances, including obtaining removal,
export and import authority if the gas is transported from Canada; the
possibility of interruption of the gas supply or transportation (depending on
the quality of the gas reserves purchased or dedicated to the project, the
financial and operating strength of the gas supplier, and whether firm or
non-firm transportation is purchased); and obligations to take a minimum
quantity of gas and pay for it (i.e., take-and-pay obligations).
Pursuant to the Natural Gas Act, FERC has jurisdiction over the
transportation and storage of natural gas in interstate commerce. With respect
to most transactions that do not involve the construction of pipeline
facilities, regulatory authorization can be obtained on a self-implementing
basis. However, pipeline rates for
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such services are subject to continuing FERC oversight. Order No. 636, issued by
FERC in April 1992, mandates the restructuring of interstate natural gas
pipeline sales and transportation services and will result in changes in the
terms and conditions under which interstate pipelines will provide
transportation services, as well as the rates pipelines may charge for such
services. The restructuring required by the rule includes (i) the separation
(unbundling) of a pipeline's sales and transportation services, (ii) the
implementation of a straight fixed-variable rate design methodology under which
all of a pipeline's fixed costs are recovered through its reservation charge,
(iii) the implementation of a capacity releasing mechanism under which holders
of firm transportation capacity on pipelines can release that capacity for
resale by the pipeline and (iv) the opportunity for pipelines to recover 100% of
their prudently incurred costs (transition costs) associated with implementing
the restructuring mandated by the rule. Pipelines were required to file tariff
sheets implementing Order No. 636 by December 31, 1992. FERC affirmed the major
components of Order No. 636 in Order Nos. 636A and B issued in August and
November 1992. The restructuring required by the rule became effective in late
1993.
STATE REGULATION
State public utility commissions ("PUCs") have historically had broad
authority to regulate both the rates charged by, and the financial activities
of, electric utilities and to promulgate regulation for implementation of PURPA.
Since a power sales agreement becomes a part of a utility's cost structure
(generally reflected in its retail rates), power sales agreements with
independent electricity producers are potentially under the regulatory purview
of PUCs and in particular the process by which the utility has entered into the
power sales agreements. If a PUC has approved the process by which a utility
secures its power supply, a PUC is generally inclined to "pass through" the
expense associated with an independent power contract to the utility's retail
customer. However, a regulatory commission under certain circumstances may
disallow the full reimbursement to a utility for the cost to purchase power from
a QF. In addition, retail sales of electricity or thermal energy by an
independent power producer may be subject to PUC regulation depending on state
law. Independent power producers which are not QFs under PURPA, or EWGs pursuant
to the Energy Policy Act of 1992, are considered to be public utilities in many
states and are subject to broad regulation by a PUC, ranging from requirement of
certificate of public convenience and necessity to regulation of organizational,
accounting, financial and other corporate matters. States may assert
jurisdiction over the siting and construction of electric generating facilities
including QFs and, with the exception of QFs, over the issuance of securities
and the sale or other transfer of assets by these facilities.
The California Public Utilities Commission ("CPUC") and the California
Joint Legislative Committee on Lowering the Cost of Electric Services commenced
proceedings and hearings related to the restructure of the California electric
services industry in 1994. The proceedings and hearings were initiated as a
result of the CPUC study and Order Instituting Rulemaking and Order Instituting
Investigation on the Commission's Proposed Policies Governing Restructuring
California's Electric Services Industry and Reforming Regulation, issued by the
CPUC on April 20, 1994. The FERC, as authorized under the Energy Policy Act of
1992, has also initiated proceedings and continues to hold workshops and
hearings on policy issues related to a more competitive electric services
industry. Though the state of California appears to be at the forefront, many
other states are in various stages of review and interest in deregulation,
moving toward a more competitive electric services industry.
On December 20, 1995, the CPUC issued its decision on California electric
industry restructure which envisioned commencement of deregulation and
implementation of customer choice beginning January 1, 1998, with all customers
participating by 2003. The decision provided for phased-in customer choice,
development of a non-discriminatory market structure, full recovery of utility
stranded costs, sanctity of existing contracts, and continuation of existing
public purpose programs including promotion of fuel diversity through a
renewable energy purchase requirement. On February 5, 1996, the CPUC issued a
procedural plan to facilitate the transition of the electric generation market
to competition. The electric restructuring roadmap focused on the multiple and
interrelated tasks to be accomplished and set forth the process to achieve the
necessary procedural milestones to be completed in order to meet the restructure
implementation goal.
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In 1996, the Joint Legislative Conference Committee held hearings related
to electric industry restructure and drafted legislation, AB 1890 (the "Bill"),
which was approved by the legislature in August 1996 and signed by the Governor
on September 23, 1996. The legislation codifies much of the December CPUC
decision as modified in January 1996 and directed the CPUC to proceed with
resolve of outstanding issues resulting in implementation of restructure no
later than January 1, 1998. The Bill accelerated the transition period in which
utilities are allowed to recover their stranded costs from five years to four
years, continued to provide for sanctity of existing contracts with provisions
for voluntary restructure, established an electricity rate freeze for the
transition period and mandated a 10% rate reduction effective January 1, 1998
for small commercial and residential customers through issuance of rate
reduction bonds, and replaced the CPUC renewable technology purchase requirement
with funds specified for use in public service programs.
On December 20, 1996, the CPUC responded to the legislation and issued an
updated procedural roadmap consistent with provisions included in the Bill.
Proceedings are ongoing at the CPUC and FERC for establishment of an Independent
Systems Operator ("ISO") responsible for centralized control and efficient and
reliable operation of the state-wide electric transmission grid, and a Power
Exchange ("PX") responsible for an efficient competitive electric energy auction
open on a non-discriminatory basis to all electric services providers. Other
proceedings now ongoing include the quantification and qualification of utility
stranded costs to be eligible for recovery through competitive transition
charges ("CTC"), market power mitigation through utility divestiture of fossil
generation plants (Pacific Gas & Electric 50%; Southern California Edison,
100%), the unbundling and establishment of rate structure for historical utility
functions, the continuation of public purpose programs and issues related to
issuance of rate reduction bonds. On May 6, 1997, the CPUC issued decisions
which eliminated phase-in and provided for implementation of direct access for
all customers beginning January 1, 1998, and the unbundling of revenue cycle
services, thereby allowing all electric service providers to participate in
metering and billing services. The CPUC has subsequently extended the
implementation date to April 1, 1998.
The California Energy Commission ("CEC") and Legislature have
responsibility for development of a competitive market mechanism for allocation
and distribution of funds made available by the legislation for enhancement of
in-state renewable resource technologies and public interest research and
development programs. Funds are to be available through the four-year transition
period to a fully competitive electric services industry.
In addition to the significant opportunity provided for power producers
such as Calpine through implementation of customer choice (direct access), the
CPUC decision and the AB 1890 restructuring legislation both recognize the
sanctity of existing contracts, provide for mitigation of utility horizontal
market power through divestiture of fossil generation and provide funds for
continuation of public services programs including fuel diversity through
enhancement for in-state renewable technologies (includes geothermal) for the
four-year transition period to a fully competitive electric services industry.
State PUCs also have jurisdiction over the transportation of natural gas by
local distribution companies ("LDCs"). Each state's regulatory laws are somewhat
different; however, all generally require the LDC to obtain approval from the
PUC for the construction of facilities and transportation services if the LDC's
generally applicable tariffs do not cover the proposed transaction. LDC rates
are usually subject to continuing PUC oversight.
REGULATION OF CANADIAN GAS
The Canadian natural gas industry is subject to extensive regulation by
governmental authorities. At the federal level, a party exporting gas from
Canada must obtain an export license from the Canadian National Energy Board
("NEB"). The NEB also regulates Canadian pipeline transportation rates and the
construction of pipeline facilities. Gas producers also must obtain a removal
permit or license from provincial authorities before natural gas may be removed
from the province, and provincial authorities may regulate intra-provincial
pipeline and gathering systems. In addition, a party importing natural gas into
the United States first must obtain an import authorization from the U.S.
Department of Energy.
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ENVIRONMENTAL REGULATIONS
The exploration for and development of geothermal resources and the
construction and operation of power projects are subject to extensive federal,
state and local laws and regulations adopted for the protection of the
environment and to regulate land use. The laws and regulations applicable to the
Company primarily involve the discharge of emissions into the water and air and
the use of water, but can also include wetlands preservation, endangered
species, waste disposal and noise regulations. These laws and regulations in
many cases require a lengthy and complex process of obtaining licenses, permits
and approvals from federal, state and local agencies.
Noncompliance with environmental laws and regulations can result in the
imposition of civil or criminal fines or penalties. In some instances,
environmental laws also may impose clean-up or other remedial obligations in the
event of a release of pollutants or contaminants into the environment. The
following federal laws are among the more significant environmental laws as they
apply to the Company. In most cases, analogous state laws also exist that may
impose similar, and in some cases more stringent, requirements on the Company as
those discussed below.
Clean Air Act
The Federal Clean Air Act of 1970 (the "Clean Air Act") provides for the
regulation, largely through state implementation of federal requirements, of
emissions of air pollutants from certain facilities and operations. As
originally enacted, the Clean Air Act sets guidelines for emissions standards
for major pollutants (i.e., sulfur dioxide and nitrogen oxide) from newly built
sources. In late 1990, Congress passed the Clean Air Act Amendments (the "1990
Amendments"). The 1990 Amendments attempt to reduce emissions from existing
sources, particularly previously exempted older power plants. The Company
believes that all of the Company's operating plants are in compliance with
federal performance standards mandated for such plants under the Clean Air Act
and the 1990 Amendments. With respect to its Aidlin geothermal plant and one of
its steam field pipelines, the Company's operations have, in certain instances,
necessitated variances under applicable California air pollution control laws.
However, the Company believes that it is in compliance with such laws with
respect to such facilities.
Clean Water Act
The Federal Clean Water Act (the "Clean Water Act") establishes rules
regulating the discharge of pollutants into waters of the United States. The
Company is required to obtain a wastewater and storm water discharge permit for
wastewater and runoff, respectively, from certain of the Company's facilities.
The Company believes that, with respect to its geothermal operations, it is
exempt from newly promulgated federal storm water requirements. The Company
believes that it is in compliance with applicable discharge requirements under
the Clean Water Act.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act ("RCRA") regulates the
generation, treatment, storage, handling, transportation and disposal of solid
and hazardous waste. The Company believes that it is exempt from solid waste
requirements under RCRA. However, particularly with respect to its solid waste
disposal practices at the power generation facilities and steam fields located
at The Geysers, the Company is subject to certain solid waste requirements under
applicable California laws. The Company believes that its operations are in
compliance with such laws.
Comprehensive Environmental Response, Compensation, and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended ("CERCLA" or "Superfund"), requires cleanup of sites from which
there has been a release or threatened release of hazardous substances and
authorizes the United States Environmental Protection Agency ("EPA") to take any
necessary response action at Superfund sites, including ordering potentially
responsible parties ("PRPs") liable for the release to take or pay for such
actions. PRPs are broadly defined under CERCLA to
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include past and present owners and operators of, as well as generators of
wastes sent to, a site. As of the present time, the Company is not subject to
liability for any Superfund matters. However, the Company generates certain
wastes, including hazardous wastes, and sends certain of its wastes to
third-party waste disposal sites. As a result, there can be no assurance that
the Company will not incur liability under CERCLA in the future.
RISK FACTORS
SUBSTANTIAL LEVERAGE
The Company is substantially leveraged as a result of outstanding
indebtedness of the Company and non-recourse debt financing of certain of the
Company's subsidiaries incurred to finance the acquisition and development of
power generation facilities. As of December 31, 1997, the Company's total
consolidated indebtedness was $855.9 million, its total consolidated assets were
$1.4 billion and its stockholders' equity was $240.0 million. The ability of the
Company to meet its debt service obligations and to repay outstanding
indebtedness according to its terms will be dependent primarily upon the
performance of the power generation facilities in which the Company has an
interest.
On September 25, 1996, the Company entered into a $50.0 million three-year
revolving credit facility with The Bank of Nova Scotia as agent (the "Revolving
Credit Facility"). The Revolving Credit Facility contains certain restrictions
that significantly limit or prohibit, among other things, the ability of the
Company or its subsidiaries to incur indebtedness, make prepayments of certain
indebtedness, pay dividends, make investments, engage in transactions with
affiliates, create liens, sell assets and engage in mergers and consolidations.
The Company believes that, based on current levels of operations and
anticipated growth, cash flow from operations, together with other available
sources of funds, including borrowings under the Company's existing borrowing
arrangements, will be adequate to make required payments of principal and
interest on the Company's debt, including the 8 3/4% Senior Notes, the 10 1/2%
Senior Notes and the 9 1/4% Senior Notes, and to enable the Company to comply
with the terms of its Indentures and other debt agreements, although there can
be no assurance that this will be the case. If the Company is unable to comply
with the terms of its Indentures and other debt agreements and fails to generate
sufficient cash flow from operations in the future, the Company may be required
to refinance all or a portion of its existing debt or to obtain additional
financing. There can be no assurance that any such refinancing would be possible
or that any additional financing could be obtained, particularly in view of the
Company's high levels of debt and the debt incurrence restrictions under
existing Indentures and other debt agreements. If cash flow is insufficient and
no such refinancing or additional financing is available, the Company may be
forced to default on its debt obligations. In the event of a default under the
terms of any of the indebtedness of the Company, subject to the terms of such
indebtedness, the obligees thereunder would be permitted to accelerate the
maturity of such obligations, which could cause defaults under other obligations
of the Company.
POSSIBLE UNAVAILABILITY OF FINANCING
Each power generation facility acquired or developed by the Company will
require substantial capital investment. The Company's ability to arrange
financing and the cost of such financing are dependent upon numerous factors,
including general economic and capital market conditions, conditions in energy
markets, regulatory developments, credit availability from banks or other
lenders, investor confidence in the industry and the Company, the continued
success of the Company's current power generation facilities, and provisions of
tax and securities laws that are conducive to raising capital. There can be no
assurance that financing for new facilities will be available to the Company on
acceptable terms in the future.
The Company's power generation facilities have been financed using a
variety of leveraged financing structures, primarily consisting of non-recourse
project financing and lease obligations. As of December 31, 1997, the Company
had approximately $855.9 million of total consolidated indebtedness, of which
approximately 35% represented non-recourse project financing. Each non-recourse
project financing and lease
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obligation is structured to be fully paid out of cash flow provided by the
facility or facilities, the assets of which (together with pledges of stock or
partnership interests in the entity owning the facility) collateralize such
obligations, without any claim against the Company's general corporate funds.
Such leveraged financing permits the development of larger facilities, but also
increases the risk to the Company that its interest in a particular facility
could be impaired or that fluctuations in revenues could adversely affect the
Company's ability to meet its lease or debt obligations. The debt collateralized
by the interests of the Company in each operating facility reduces the liquidity
of such assets since any sale or transfer of a facility would be subject both to
the lien securing the facility indebtedness and to transfer restrictions in the
financing agreements. While the Company intends to utilize non-recourse or lease
financing when appropriate, there can be no assurance that market conditions and
other factors will permit the same limited equity investment by the Company or
the same substantially non-recourse nature of financings for future facilities.
In the event of a default under a financing agreement, and assuming the Company
or the other equity investors in a facility are unable or choose not to cure
such default within applicable cure periods, if any, the lenders or lessors
would generally have rights to the facility, any related geothermal resource or
natural gas reserves, related contracts and cash flows and all licenses and
permits necessary to operate the facility. In the event of foreclosure after
such a default, the Company might not retain any interest in such facility. The
Company does not believe the existence of non-recourse or lease financing will
materially affect its ability to continue to borrow funds in the future in order
to finance new facilities. There can be no assurance, however, that the Company
will continue to be able to obtain the financing required to develop its power
generation facilities on terms satisfactory to the Company.
The Company has from time to time guaranteed certain obligations of its
subsidiaries and other affiliates. There can be no assurance that, in respect of
any financings of facilities in the future, lenders or lessors will not require
the Company to guarantee the indebtedness of such future facilities, rendering
the Company's general corporate funds vulnerable in the event of a default by
such facility or related subsidiary.
IMPACT OF AVOIDED COST PRICING; ENERGY PRICE FLUCTUATIONS
PG&E pays a fixed price for each unit of electrical energy according to
schedules set forth in the long-term power sales agreements for the Bear Canyon
(20 megawatts) and West Ford Flat (27 megawatts) Power Plants. The fixed price
periods under these power sales agreements expire in September and December
1998, respectively. After the fixed price periods expire, while the basis for
the capacity and capacity bonus payments under these power sales agreements
remains the same, the energy payments adjust to interim short-run avoided cost
("SRAC"), which is calculated pursuant to the methodology approved by the CPUC
on December 9, 1996, and will continue at SRAC until the independent power
exchange has commenced operations and is functioning properly. The independent
power exchange is currently scheduled to commence operations on April 1, 1998.
Thereafter, SRAC will become the energy clearing price of the independent power
exchange (referred to herein as the "Power Exchange Price"). During 1997, SRAC
averaged approximately 2.94c per kilowatt hour. As a result, while SRAC does not
affect capacity payments under the power sales agreements, the Company's energy
revenue under these power sales agreements is expected to be materially reduced
at the expiration of the fixed price period. Such reduction may have a material
adverse effect on the Company's results of operations. The Company expects the
forecasted decline in energy revenues will be mitigated by decreased royalty
expenses and planned operating cost reductions at the facilities. In addition,
the Company will continue its strategy of offsetting such reductions through its
acquisition and development program. In addition, prices paid for the steam
delivered by the Company's steam fields are based on a formula that partially
reflects the price levels of nuclear and fossil fuels, and, therefore, a
reduction in the price levels of such fuels may reduce revenue under the steam
sales agreements for the steam fields.
POWER PROJECT DEVELOPMENT AND ACQUISITION RISKS
The development of power generation facilities is subject to substantial
risks. In connection with the development of a power generation facility, the
Company must generally obtain governmental permits and
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approvals, fuel supply and transportation agreements, sufficient equity capital
and debt financing, electrical transmission agreements, site agreements and
construction contracts, and there can be no assurance that the Company will be
successful in doing so. In addition, project development is subject to certain
environmental, engineering and construction risks relating to cost-overruns,
delays and performance. Although the Company may attempt to minimize the
financial risks in the development of a project by securing a favorable
long-term power sales agreement, entering into power marketing transactions,
obtaining all required governmental permits and approvals and arranging adequate
financing prior to the commencement of construction, the development of a power
project may require the Company to expend significant sums for preliminary
engineering, permitting, legal and other expenses before it can be determined
whether a project is feasible, economically attractive or financeable. If the
Company were unable to complete the development of a facility, it would
generally not be able to recover its investment in such a facility. The process
for obtaining initial environmental, siting and other governmental permits and
approvals is complicated and lengthy, often taking more than one year, and is
subject to significant uncertainties. As a result of competition, it may be
difficult to obtain a power sales agreement for a proposed project, and the
prices offered in new power sales agreements for both electric capacity and
energy may be less than the prices in prior agreements. There can be no
assurance that the Company will be successful in the development of power
generation facilities in the future.
The Company has grown substantially in recent years as a result of
acquisitions of interests in power generation facilities and steam fields. The
Company believes that although the domestic power industry is undergoing
consolidation and that significant acquisition opportunities are available, the
Company is likely to confront significant competition for acquisition
opportunities. In addition, there can be no assurance that the Company will
continue to identify attractive acquisition opportunities at favorable prices
or, to the extent that any opportunities are identified, that the Company will
be able to consummate such acquisitions.
START-UP RISKS
The commencement of operation of a newly constructed power plant or steam
field involves many risks, including start-up problems, the breakdown or failure
of equipment or processes and performance below expected levels of output or
efficiency. New plants have no operating history and may employ recently
developed and technologically complex equipment. Insurance is maintained to
protect against certain of these risks, warranties are generally obtained for
limited periods relating to the construction of each project and its equipment
in varying degrees, and contractors and equipment suppliers are obligated to
meet certain performance levels. Such insurance, warranties or performance
guarantees may not be adequate to cover lost revenues or increased expenses and,
as a result, a project may be unable to fund principal and interest payments
under its financing obligations and may operate at a loss. A default under such
a financing obligation could result in the Company losing its interest in such
power generation facility or steam field.
In addition, power sales agreements, which are typically entered into with
a utility early in the development phase of a project, often enable the utility
to terminate such agreement, or to retain security posted as liquidated damages,
in the event that a project fails to achieve commercial operation or certain
operating levels by specified dates or fails to make certain specified payments.
In the event such a termination right is exercised, a project may not commence
generating revenues, the default provisions in a financing agreement may be
triggered (rendering such debt immediately due and payable) and the project may
be rendered insolvent as a result.
GENERAL OPERATING RISKS
The Company currently operates 16 out of 23 of the power generation
facilities and steam fields in which it has an interest. The continued operation
of power generation facilities and steam fields involves many risks, including
the breakdown or failure of power generation equipment, transmission lines,
pipelines or other equipment or processes and performance below expected levels
of output or efficiency. To date, the Company's power generation facilities have
operated at an average availability of approximately 97%, and although from time
to time the Company's power generation facilities and steam fields have
experienced certain equipment breakdowns or failures, such breakdowns or
failures have not had a material adverse effect on the operation of such
facilities or on the Company's results of operations. Although the Company's
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facilities contain certain redundancies and back-up mechanisms, there can be no
assurance that any such breakdown or failure would not prevent the affected
facility or steam field from performing under applicable power and/or steam
sales agreements. In addition, although insurance is maintained to protect
against certain of these operating risks, the proceeds of such insurance may not
be adequate to cover lost revenues or increased expenses, and, as a result, the
entity owning such power generation facility or steam field may be unable to
service principal and interest payments under its financing obligations and may
operate at a loss. A default under such a financing obligation could result in
the Company losing its interest in such power generation facility or steam
field.
RISKS RELATED TO THE DEVELOPMENT AND OPERATION OF GEOTHERMAL ENERGY RESOURCES
The development and operation of geothermal energy resources are subject to
substantial risks and uncertainties similar to those experienced in the
development of oil and gas resources. The successful exploitation of a
geothermal energy resource ultimately depends upon the heat content of the
extractable fluids, the geology of the reservoir, the total amount of
recoverable reserves and operational factors relating to the extraction of
fluids, including operating expenses, energy price levels and capital
expenditure requirements relating primarily to the drilling of new wells. In
connection with the development of a project, the Company estimates the
productivity of the geothermal resource and the expected decline in such
productivity. The productivity of a geothermal resource may decline more than
anticipated, resulting in insufficient recoverable reserves being available for
sustained generation of the electrical power capacity desired. An incorrect
estimate by the Company or an unexpected decline in productivity could have a
material adverse effect on the Company's results of operations.
Geothermal reservoirs are highly complex, and, as a result, there exist
numerous uncertainties in determining the extent of the reservoirs and the
quantity and productivity of the steam reserves. Reservoir engineering is an
inexact process of estimating underground accumulations of steam or fluids that
cannot be measured in any precise way, and depends significantly on the quantity
and accuracy of available data. As a result, the estimates of other reservoir
specialists may differ materially from those of the Company. Estimates of
reserves are generally revised over time on the basis of the results of
drilling, testing and production that occur after the original estimate was
prepared. While the Company has extensive experience in the operation and
development of geothermal energy resources and in preparing such estimates,
there can be no assurance that the Company will be able to successfully manage
the development and operation of its geothermal reservoirs or that the Company
will accurately estimate the quantity or productivity of its steam reserves.
DEPENDENCE ON THIRD PARTIES
The nature of the Company's power generation facilities is such that each
facility generally relies on one power or steam sales agreement with a single
electric utility customer for substantially all, if not all, of such facility's
revenue over the life of the project. During 1997, approximately 80% and 5% of
the Company's total revenue was attributable to revenue received pursuant to
power and steam sales agreements with PG&E and SMUD, respectively. The power and
steam sales agreements are generally long-term agreements, covering the sale of
electricity or steam for initial terms of 20 or 30 years. However, the loss of
any one power or steam sales agreement with any of these utility customers could
have a material adverse effect on the Company's results of operations. In
addition, any material failure by any utility customer to fulfill its
obligations under a power or steam sales agreement could have a material adverse
effect on the cash flow available to the Company and, as a result, on the
Company's results of operations. PG&E has recently announced its intention to
sell all of its power generating facilities in The Geysers that purchase steam
from TPC and the PG&E Unit 13 and PG&E Unit 16 Steam Fields. Although there can
be no assurance, the Company does not expect that such sale, if consummated,
would have a material adverse impact on the Company's results of operations or
financial condition.
Furthermore, each power generation facility may depend on a single or
limited number of entities to purchase thermal energy, or to supply or transport
natural gas to such facility. The failure of any one utility customer, steam
host, gas supplier or gas transporter to fulfill its contractual obligations
could have a material adverse effect on a power project and on the Company's
business and results of operations.
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INTERNATIONAL INVESTMENTS
The Company has made an investment in the Cerro Prieto geothermal steam
fields located in Mexico and may pursue additional international investments, in
selected countries. Such investments are subject to risks and uncertainties
relating to the political, social and economic structures of those countries.
Risks specifically related to investments in non-United States projects may
include risks of fluctuations in currency valuation, currency inconvertibility,
expropriation and confiscatory taxation, increased regulation and approval
requirements and governmental policies limiting returns to foreign investors.
GOVERNMENT REGULATION
The Company's activities are subject to complex and stringent energy,
environmental and other governmental laws and regulations. The construction and
operation of power generation facilities require numerous permits, approvals and
certificates from appropriate federal, state and local governmental agencies, as
well as compliance with environmental protection legislation and other
regulations. While the Company believes that it has obtained the requisite
approvals for its existing operations and that its business is operated in
accordance with applicable laws, the Company remains subject to a varied and
complex body of laws and regulations that both public officials and private
individuals may seek to enforce. There can be no assurance that existing laws
and regulations will not be revised or that new laws and regulations will not be
adopted or become applicable to the Company that may have a material adverse
effect on the Company's business or results of operations, nor can there be any
assurance that the Company will be able to obtain all necessary licenses,
permits, approvals and certificates for proposed projects or that completed
facilities will comply with all applicable permit conditions, statutes or
regulations. In addition, regulatory compliance for the construction of new
facilities is a costly and time consuming process, and intricate and changing
environmental and other regulatory requirements may necessitate substantial
expenditures to obtain permits and may create a significant risk of expensive
delays or significant loss of value in a project if the project is unable to
function as planned due to changing requirements or local opposition.
The Company's operations are subject to the provisions of various energy
laws and regulations, including PURPA, PUHCA, and state and local regulations.
PUHCA provides for the extensive regulation of public utility holding companies
and their subsidiaries. PURPA provides to QFs and owners of QFs certain
exemptions from certain federal and state regulations, including rate and
financial regulations.
Under present federal law, the Company is not and will not be subject to
regulation as a holding company under PUHCA as long as the power plants in which
it has an interest are QFs under PURPA or are subject to another exemption. In
order to be a QF, a facility must be not more than 50% owned by an electric
utility or electric utility holding company. A QF that is a cogeneration
facility must produce not only electricity, but also useful thermal energy for
use in an industrial or commercial process or heating or cooling applications in
certain proportions to the facility's total energy output, and it must meet
certain energy efficiency standards. Therefore, loss of a thermal energy
customer could jeopardize a cogeneration facility's QF status. All geothermal
power plants up to 80 megawatts that meet PURPA's ownership requirements and
certain other standards are considered QFs. If one of the power plants in which
the Company has an interest were to lose its QF status and not otherwise receive
a PUHCA exemption, the project subsidiary or partnership in which the Company
has an interest owning or leasing that plant could become a public utility
company, which could subject the Company to significant federal, state and local
laws, including rate regulation and regulation as a public utility holding
company under PUHCA. This loss of QF status, which may be prospective or
retroactive, in turn, could cause all of the Company's other power plants to
lose QF status because, under FERC regulations, a QF cannot be owned by an
electric utility or electric utility holding company. In addition, a loss of QF
status could, depending on the power sales agreement, allow the power purchaser
to cease taking and paying for electricity or to seek refunds of past amounts
paid and thus could cause the loss of some or all contract revenues or otherwise
impair the value of a project and could trigger defaults under provisions of the
applicable project contracts and financing agreements (rendering such debt
immediately due and payable). If a power purchaser ceased taking and paying for
electricity or sought to obtain refunds of past amounts paid, there can be no
assurance that the costs incurred in connection with the project could be
recovered through sales to other purchasers.
39
<PAGE> 42
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at avoided costs. The Company does not know whether such legislation will be
passed or what form it may take. The Company believes that if any such
legislation is passed, it would apply to new projects. As a result, although
such legislation may adversely affect the Company's ability to develop new
projects, the Company believes it would not affect the Company's existing QFs.
There can be no assurance, however, that any legislation passed would not
adversely impact the Company's existing projects.
Many states are implementing or considering regulatory initiatives designed
to increase competition in the domestic power generation industry. In a December
20, 1995 policy decision, the CPUC outlined a new market structure that would
provide for a competitive power generation industry and direct access to
generation for all consumers within five years. The CPUC has issued decisions
which provide for direct access for all customers beginning April 1, 1998, and
the unbundling of all electric services. As part of its policy decision, the
CPUC indicated that power sales agreements of existing QFs would be honored. The
Company cannot predict the final form or timing of the proposed restructuring
and the impact, if any, that such restructuring would have on the Company's
existing business or results of operations.
SEISMIC DISTURBANCES
Areas in which the Company operates and is developing many of its
geothermal and gas-fired projects are subject to frequent low-level seismic
disturbances, and more significant seismic disturbances are possible. While the
Company's existing power generation facilities are built to withstand relatively
significant levels of seismic disturbances, and the Company believes it
maintains adequate insurance protection, there can be no assurance that
earthquake, property damage or business interruption insurance will be adequate
to cover all potential losses sustained in the event of serious seismic
disturbances or that such insurance will continue to be available to the Company
on commercially reasonable terms.
AVAILABILITY OF NATURAL GAS
To date, the Company's fuel acquisition strategy has included various
combinations of Company-owned gas reserves, gas prepayment contracts and short,
medium and long-term supply contracts. In its gas supply arrangements, the
Company attempts to match the fuel cost with the fuel component included in the
facility's power sales agreements, in order to minimize a project's exposure to
fuel price risk. The Company believes that there will be adequate supplies of
natural gas available at reasonable prices for each of its facilities when
current gas supply agreements expire. There can be no assurance, however, that
gas supplies will be available for the full term of the facilities' power sales
agreements, or that gas prices will not increase significantly. If gas is not
available, or if gas prices increase above the fuel component of the facilities'
power sales agreements, there could be a material adverse impact on the
Company's results of operations.
COMPETITION
The power generation industry is characterized by intense competition, and
the Company encounters competition from utilities, industrial companies and
other power producers. In recent years, there has been increasing competition in
an effort to obtain power sales agreements, and this competition has contributed
to a reduction in electricity prices. In addition, many states are implementing
or considering regulatory initiatives designed to increase competition in the
domestic power industry. In California, the CPUC has issued decisions which
provide for direct access for all customers beginning April 1, 1998. Regulatory
initiatives are also being considered in other states, including Texas, New York
and states in New England. This competition has put pressure on electric
utilities to lower their costs, including the cost of purchased electricity, and
increasing competition in the future will increase this pressure.
40
<PAGE> 43
DEPENDENCE ON SENIOR MANAGEMENT
The Company's success is largely dependent on the skills, experience and
efforts of its senior management. The loss of the services of one or more
members of the Company's senior management could have a material adverse effect
on the Company's business and development. To date, the Company generally has
been successful in retaining the services of its senior management.
QUARTERLY FLUCTUATIONS; SEASONALITY
The Company's quarterly operating results have fluctuated in the past and
may continue to do so in the future as a result of a number of factors,
including but not limited to the timing and size of acquisitions, the completion
of development projects, the timing and amount of curtailment, if any, and
variations in levels of production. Furthermore, the majority of capacity
payments under certain of the Company's power sales agreements are received
during the months of May through October.
EMPLOYEES
As of December 31, 1997, the Company employed 356 people. None of the
Company's employees are covered by collective bargaining agreements, and the
Company has never experienced a work stoppage, strike or labor dispute. The
Company considers relations with its employees to be good.
ITEM 2. PROPERTIES
The Company's principal executive office is located in San Jose, California
under a lease that expires in June 2001.
The Company, through its ownership of CGC and TPC, has leasehold interests
in 109 leases comprising 27,263 acres of federal, state and private geothermal
resource lands in The Geysers area in northern California. These leases comprise
its West Ford Flat Power Plant, Bear Canyon Power Plant, PG&E Unit 13 and Unit
16 Steam Fields, SMUDGEO #1 Steam Fields TPC's 25% undivided interest in the TPC
Steam Fields which are operated by Union Oil. In the Glass Mountain and Medicine
Lake areas in northern California, the Company holds leasehold interests in 18
leases comprising approximately 25,028 acres of federal geothermal resource
lands.
In general, under the leases, the Company has the exclusive right to drill
for, produce and sell geothermal resources from these properties and the right
to use the surface for all related purposes. Each lease requires the payment of
annual rent until commercial quantities of geothermal resources are established.
After such time, the leases require the payment of minimum advance royalties or
other payments until production commences, at which time production royalties
are payable. Such royalties and other payments are payable to landowners, state
and federal agencies and others, and vary widely as to the particular lease. The
leases are generally for initial terms varying from 10 to 20 years or for so
long as geothermal resources are produced and sold. Certain of the leases
contain drilling or other exploratory work requirements. In certain cases, if a
requirement is not fulfilled, the lease may be terminated and in other cases
additional payments may be required. The Company believes that its leases are
valid and that it has complied with all the requirements and conditions material
to their continued effectiveness. A number of the Company's leases for
undeveloped properties may expire in any given year. Before leases expire, the
Company performs geological evaluations in an effort to determine the resource
potential of the underlying properties. No assurance can be given that the
Company will decide to renew any expiring leases.
The Company, through its ownership of the Greenleaf 1 Power Plant, owns 77
acres in Sutter County, California.
The Company owns the Calpine Gas Company, which includes 112 leases
covering approximately 16,094 gross acres and 15,037 net acres. The Company
believes that its properties are adequate for its current operations.
41
<PAGE> 44
ITEM 3. LEGAL PROCEEDINGS
On September 30, 1997, a lawsuit was filed by Indeck North American Power
Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb
plc. and certain other parties, including the Company. Some of Indeck's claims
relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in
Gordonsville Energy L.P. from Northern Hydro Limited and Calpine Auburndale,
Inc.'s acquisition of a 50% interest in Auburndale Power Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck is claiming that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. All of the defendants have filed motions to dismiss
such claims, which are currently pending. The Company believes that the claims
of Indeck are without merit and that the resolution of this matter will not have
a material adverse effect on the Company's financial position or results of
operations.
On February 17, 1998, the Company filed an action in the Superior Court of
California, Sonoma County, seeking injunctive and declaratory relief to prevent
PG&E from unilaterally assigning the Company's steam sales contract to the
prospective winning bidder in PG&E's recently announced auction of its power
plants in The Geysers. On January 14, 1998, PG&E filed an application with the
CPUC pursuant to Public Utilities Code Section 851 ("851 Filing"), in which it
seeks authorization to sell five electric generating plants and related assets.
Included in this proposed sale are The Geysers Geothermal Power Plants
(including Units 13 and 16) and certain of PG&E's fossil fueled steam-electric
generating plants. In PG&E's 851 Filing, PG&E announced its intention to assign
its rights and to delegate its duties under the Company's steam contract to the
successful third party purchaser of the Unit 13 and Unit 16 Power Plants. The
Company has been informed by PG&E that it will attempt to make such assignment
and delegation without first seeking and obtaining the approval and consent of
the Company. The Company is challenging the continued validity of the price term
of the steam sales contract following the proposed divestiture by PG&E of 98% of
its fossil fueled steam-electric generating plants, as the price term of the
steam sales contract is based on a complex formula that reflects PG&E's weighted
average cost of fossil and nuclear fuel from the preceding year.
In a related action, the Company has filed a protest with the CPUC which
raises issues similar to those addressed in the above-referenced lawsuit and, in
addition, challenges certain inaccuracies contained in portions of PG&E's 851
Filings related to Unit 13 and Unit 16. As no discovery has been conducted in
either matter, nor has any answer been filed in the lawsuit, the Company is
unable to predict the outcome of these cases.
An action was filed against Lockport Energy Associates, L.P. ("LEA") on
August 7, 1997 by New York State Electricity and Gas Company ("NYSEG") in the
Federal District Court for the Northern District of New York. NYSEG has
requested the Court to direct the Federal Energy Regulatory Commission (the
"FERC") and the New York Public Service Commission ("NYPSC"), to modify contract
rates to be paid to the Lockport Power Plant. On October 14, 1997, NYPSC, a
named defendant in the NYSEG action, filed a cross-claim alleging that the FERC
violated PURPA and the Federal Power Act by failing to reform the NYSEG contract
which was previously approved by the NYPSC. LEA continues to vigorously defend
this action, although it is unable to predict the outcome of this case. The
Company retains the right to require The Brooklyn Union Gas Company ("BUG") to
purchase the Company's interest in the Lockport Power Plant for $18.9 million,
less equity distributions received by the Company, at any time before December
19, 2001. In the event the NYSEG's action is successful, the Company may choose
to exercise its right to require BUG to purchase its interest in the Lockport
Power Plant.
There is currently a dispute between Texas-New Mexico Power Company ("TNP")
and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear
Lake Power Plant, regarding certain costs and other amounts that TNP has
withheld from payments due under the power sales agreement. As of December 31,
1997, TNP has withheld approximately $5.4 million related to transmission
charges and has continued to withhold approximately $450,000 per month
thereafter. CLC filed a petition for declaratory order with the Texas Public
Utilities Commission ("Texas PUC") on October 2, 1997 requesting that the Texas
PUC declare that TNP's
42
<PAGE> 45
withholding is in error. This matter is pending before the Texas PUC. In
addition, as of December 31, 1997, TNP has withheld approximately $4.4 million
of standby power charges and has continued to withhold approximately $270,000
per month thereafter. CLC has filed a lawsuit in Texas against TNP claiming that
TNP is in breach of certain provisions of the power sales agreement, including
the provisions involved in the disputes described above, and is seeking in
excess of $15.0 million in damages. A trial is scheduled to begin on June 1,
1998. The Company is unable to predict the outcome of either of these
proceedings.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. The Company does not expect that the
outcome of these proceedings will have a material adverse effect on the
Company's financial position or results of operations, although no assurance can
be given in this regard.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information required hereunder is set forth under "Quarterly
Consolidated Financial Data" included in Appendix F, Note 29 of the Notes to
Consolidated Financial Statements to this report. The Company made no sales of
unregistered equity securities in the last three years.
ITEM 6. SELECTED FINANCIAL DATA
The information required hereunder is set forth under "Selected
Consolidated Financial Data" included in Appendix F to this report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information required hereunder is set forth under "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included in Appendix F to this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is set forth under "Report of
Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated
Statements of Operations," "Consolidated Statements of Shareholder's Equity,"
"Consolidated Statements of Cash Flows," and "Notes to Consolidated Financial
Statements" included in Appendix F of this report. Other financial information
and schedules are included in Appendix F of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS AND FINANCIAL DISCLOSURE
None.
ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES
Incorporated by reference from Proxy Statement relating to the 1998 Annual
Meeting of Shareholders.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Proxy Statement relating to the 1998 Annual
Meeting of Shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Proxy Statement relating to the 1998 Annual
Meeting of Shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
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<PAGE> 46
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A)-1. FINANCIAL STATEMENTS AND OTHER INFORMATION
The following items appear in Appendix F of this report:
Selected Consolidated Financial Data
Management's Discussion and Analysis of Financial Condition and Results
of Operations
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 1997 and 1996
Consolidated Statements of Operations for the Years Ended December 31,
1997, 1996 and 1995
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1997, 1996 and 1995
Consolidated Statements of Cash Flows for the Years Ended December 31,
1997, 1996 and 1995
Notes to Consolidated Financial Statements for the Years Ended December
31, 1997, 1996 and 1995
(A)-2. FINANCIAL STATEMENTS AND SCHEDULES
The following items appear in Appendix F of this report:
CALPINE CORPORATION
I Condensed Financial Information of Registrant
Report of Independent Public Accountants
Balance Sheets, December 31, 1997 and 1996
Statements of Operations for the Years Ended December 31, 1997, 1996
and 1995
Statements of Cash Flows for the Years Ended December 31, 1997, 1996
and 1995
Notes to Condensed Financial Statements for the Years Ended December
31, 1997, 1996 and 1995
II Valuation and Qualifying Accounts
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Independent Auditor's Report
Consolidated Balance Sheet, December 31, 1997 and 1996
Consolidated Statement of Income for the Years Ended December 31,
1997, 1996 and 1995
Consolidated Statements of Changes in Partners' Equity for the Years
Ended December 31, 1997, 1996 and 1995
Consolidated Statements of Cash Flows for the Years Ended December
31, 1997, 1996 and 1995
Notes to Consolidated Financial Statements for the Year Ended
December 31, 1997
All other schedules for which provision is made in the applicable
accounting regulation of the Securities and Exchange Commission are not required
under the related instructions or are inapplicable, and therefore have been
omitted.
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(A)-3. EXHIBITS
The following exhibits are filed herewith unless otherwise indicated:
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
3.1 -- Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(l)
3.2 -- Amended and Restated Bylaws of Calpine Corporation, a
Delaware corporation.(l)
4.1 -- Indenture dated as of February 17, 1994 between the Company
and Shawmut Bank of Connecticut, National Association, as
Trustee, including form of Notes.(a)
4.2 -- Indenture dated as of May 16, 1996 between the Company and
Fleet National Bank, as Trustee, including form of Notes.(m)
10.1 -- Financing Agreements
10.1.1 -- Term and Working Capital Loan Agreement, dated as of June 1,
1990, between Calpine Geysers Company, L.P. (formerly Santa
Rosa Geothermal Company, L.P.) and Deutsche Bank AG, New
York Branch.(a)
10.1.2 -- First Amendment to Term and Working Capital Loan Agreement,
dated as of June 29, 1990, between Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.) and
Deutsche Bank AG, New York Branch.(a)
10.1.3 -- Second Amendment to Term and Working Capital Loan Agreement,
dated as of December 1, 1990, between Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.)
and Deutsche Bank AG, New York Branch.(a)
10.1.4 -- Third Amendment to Term and Working Capital Loan Agreement,
dated as of June 26, 1992, between Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.),
Deutsche Bank AG, New York Branch, National Westminster Bank
PLC, Union Bank of Switzerland, New York Branch, and The
Prudential Insurance Company of America.(a)
10.1.5 -- Fourth Amendment to Term and Working Capital Loan Agreement,
dated as of April 1, 1993, between Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.),
Deutsche Bank AG, New York Branch, National Westminster Bank
PLC, Union Bank of Switzerland, New York Branch, and The
Prudential Insurance Company of America.(a)
10.1.6 -- Construction and Term Loan Agreement, dated as of January
30, 1992, between Sumas Cogeneration Company, L.P., The
Prudential Insurance Company of America and Credit Suisse,
New York Branch.(a)
10.1.7 -- Amendment No. 1 to Construction and Term Loan Agreement,
dated as of May 24, 1993, between Sumas Cogeneration
Company, L.P., The Prudential Insurance Company of America
and Credit Suisse, New York Branch.(a)
10.1.8 -- Credit Agreement Construction Loan and Term Loan Facility,
dated as of January 10, 1990, between Credit Suisse and
O.L.S. Energy-Agnews.(a)
10.1.9 -- Amendment No. 1 to Credit Agreement Construction Loan and
Term Loan Facility, dated as of December 5, 1990, between
Credit Suisse and O.L.S. Energy-Agnews.(a)
10.1.10 -- Participation Agreement, dated as of December 1, 1990,
between O.L.S. Energy-Agnews, Nynex Credit Company, Credit
Suisse, Meridian Trust Company of California and GATX
Capital Corporation.(a)
10.1.11 -- Facility Lease Agreement, dated as of December 1, 1990,
between Meridian Trust Company of California and O.L.S.
Energy-Agnews.(a)
</TABLE>
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<PAGE> 48
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.1.12 -- Project Revenues Agreement, dated as of December 1, 1990,
between O.L.S. Energy-Agnews, Meridian Trust Company of
California and Credit Suisse.(a)
10.1.13 -- Project Credit Agreement, dated as of June 30, 1995, between
Calpine Greenleaf Corporation, Greenleaf Unit One
Associates, Greenleaf Unit Two Associates, Inc. and The
Sumitomo Bank, Limited.(g)
10.1.14 -- Lease dated as of April 24, 1996 between BAF Energy A
California Limited Partnership, Lessor, and Calpine King
City Cogen, LLC, Lessee.(j)
10.1.15 -- Credit Agreement, dated as of August 28, 1996, among Calpine
Gilroy Cogen, L.P. and Banque Nationale de Paris.(l)
10.1.16 -- Credit Agreement, dated as of September 25, 1996, among
Calpine Corporation and The Bank of Nova Scotia.(m)
10.1.17 -- Credit Agreement, dated December 20, 1996, among Pasadena
Cogeneration L.P. and ING (U.S.) Capital Corporation and The
Bank Parties Hereto.(n)
10.2 -- Purchase Agreements
10.2.1 -- Purchase Agreement, dated as of April 1, 1993, between
Sonoma Geothermal Partners, L.P., Healdsburg Energy Company,
L.P. and Freeport-McMoRan Resource Partners, Limited
Partnership.(a)
10.2.2 -- Stock Purchase Agreement, dated as of June 27, 1994, between
Maxus International Energy Company, Natomas Energy Company,
Calpine Corporation and Calpine Thermal Power, Inc., and
amendment thereto dated July 28, 1994.(b)
10.2.3 -- Share Purchase Agreement dated March 30, 1995 between
Calpine Corporation, Calpine Greenleaf Corporation, Radnor
Power Corp. and LFC Financial Corp.(e)
10.2.4 -- Asset Purchase Agreement, dated as of August 28, 1996, among
Gilroy Energy Company, McCormick & Company, Incorporated and
Calpine Gilroy Cogen, L.P.(m)
10.2.5 -- Noncompetition/Earnings Contingency Agreement, dated as of
August 28, 1996, among Gilroy Energy Company, McCormick &
Company, Incorporated and Calpine Gilroy Cogen, L.P.(m)
10.3 -- Power Sales Agreements
10.3.1 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the Bear Canyon Facility, dated November 30,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), Amendment dated October 17, 1985, Second Amendment
dated October 19, 1988, and related documents.(a)
10.3.2 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the Bear Canyon Facility, dated November 29,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), and Modification dated November 29, 1984, Amendment
dated October 17, 1985, Second Amendment dated October 19,
1988, and related documents.(a)
10.3.3 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the West Ford Flat Facility, dated November 13,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), and Amendments dated May 18, 1987, June 22, 1987,
July 3, 1987 and January 21, 1988, and related documents.(a)
10.3.4 -- Agreement for Firm Power Purchase, dated as of February 24,
1989, between Puget Sound Power & Light Company and Sumas
Energy, Inc. and Amendment thereto dated September 30,
1991.(a)
</TABLE>
46
<PAGE> 49
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.3.5 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated April 16, 1985, between O.L.S. Energy-Agnews and
Pacific Gas & Electric Company and amendment thereto dated
February 24, 1989.(a)
10.3.6 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated November 15, 1984, between Geothermal Energy Partners,
Ltd. and Pacific Gas & Electric Company, and related
documents.(a)
10.3.7 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated November 15, 1984, between Geothermal Energy Partners,
Ltd. and Pacific Gas & Electric Company (see Exhibit 10.3.6
for related documents).(a)
10.3.8 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated December 12, 1984, between Greenleaf Unit One
Associates, Inc. and Pacific Gas and Electric Company.(f)
10.3.9 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated December 12, 1984, between Greenleaf Unit Two
Associates, Inc. and Pacific Gas and Electric Company.(f)
10.3.10 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated December 5, 1985, between Calpine Gilroy Cogen, L.P.
and Pacific Gas and Electric Company, and Amendments thereto
dated December 19, 1993, July 18, 1985, June 9, 1986, August
18, 1988 and June 9, 1991.(l)
10.3.11 -- Amended and Restated Energy Sales Agreement, dated December
16, 1996, between Phillips Petroleum Company and Pasadena
Cogeneration, L.P.(n)
10.4 -- Steam Sales Agreements
10.4.1 -- Geothermal Steam Sales Agreement, dated July 19, 1979,
between Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.), and Sacramento Municipal Utility
District, and related documents.(a)
10.4.2 -- Agreement for the Sale and Purchase of Geothermal Steam,
dated March 23, 1973, between Calpine Geysers Company, L.P.
(formerly Santa Rosa Geothermal Company, L.P.) and Pacific
Gas & Electric Company, and related letter dated May 18,
1987.(a)
10.4.3 -- Thermal Energy and Kiln Lease Agreement, dated as of January
16, 1992, between Sumas Cogeneration Company, L.P. and
Socco, Inc., and Amendment thereto dated May 24, 1993.(a)
10.4.4 -- Amended and Restated Energy Service Agreement, dated as of
December 1, 1990, between the State of California and O.L.S.
Energy-Agnews.(a)
10.4.5 -- Agreement for the Sale of Geothermal Steam, dated as of July
28, 1992, between Thermal Power Company and Pacific Gas &
Electric Company.(c)
10.4.6 -- Amendment to the Agreement for the Sale of Geothermal Steam,
dated as of August 9, 1995, between Union Oil Company of
California, NEC Acquisition Company, Thermal Power Company,
and Pacific Gas and Electric Company.(h)
10.5 -- Service Agreements
10.5.1 -- Operation and Maintenance Agreement, dated as of April 5,
1990, between Calpine Operating Plant Services, Inc.
(formerly Calpine-Geysers Plant Services, Inc.) and Calpine
Geysers Company, L.P. (formerly Santa Rosa Geothermal
Company, L.P.).(a)
10.5.2 -- Amended and Restated Operating and Maintenance Agreement,
dated as of January 24, 1992, between Calpine Operating
Plant Services, Inc. and Sumas Cogeneration Company, L.P.(a)
10.5.3 -- Amended and Restated Operation and Maintenance Agreement,
dated as of December 31, 1990, between O.L.S. Energy-Agnews
and Calpine Operating Plant Services, Inc. (formerly Calpine
Cogen-Agnews, Inc.).(a)
</TABLE>
47
<PAGE> 50
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.5.4 -- Operating and Maintenance Agreement, dated as of January 1,
1995, between Calpine Corporation and Geothermal Energy
Partners, Ltd.(h)
10.5.5 -- Amended and Restated Operating Agreement for the Geysers,
dated as of December 31, 1993, by and between Magma-Thermal
Power Project, a joint venture composed of NEC Acquisition
Company and Thermal Power Company, and Union Oil Company of
California.(c)
10.6 -- Gas Supply Agreements
10.6.1 -- Gas Sale and Purchase Agreement, dated as of December 23,
1991, between ENCO Gas, Ltd. and Sumas Cogeneration Company,
L.P.(a)
10.6.2 -- Gas Management Agreement, dated as of December 23, 1991,
between Canadian Hydrocarbons Marketing Inc., ENCO Gas, Ltd.
and Sumas Cogeneration Company, L.P.(a)
10.6.4 -- Natural Gas Sales Agreement, dated as of November 1, 1993,
between O.L.S. Energy-Agnews, Inc. and Amoco Energy Trading
Corporation.(a)
10.6.5 -- Natural Gas Service Agreement, dated November 1, 1993,
between Pacific Gas & Electric Company and O.L.S.
Energy-Agnews, Inc.(a)
10.7 -- Agreements Regarding Real Property
10.7.1 -- Office Lease, dated March 15, 1991, between 50 West San
Fernando Associates, L.P. and Calpine Corporation.(a)
10.7.2 -- First Amendment to Office Lease, dated April 30, 1992,
between 50 West San Fernando Associates, L.P. and Calpine
Corporation.(a)
10.7.3 -- Geothermal Resources Lease CA 1862, dated July 25, 1974,
between the United States Bureau of Land Management and
Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.).(a)
10.7.4 -- Geothermal Resources Lease PRC 5206.2, dated December 14,
1976, between the State of California and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.).(a)
10.7.5 -- First Amendment to Geothermal Resources Lease PRC 5206.2,
dated April 20,1994, between the State of California and
Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.).(a)
10.7.6 -- Industrial Park Lease Agreement, dated December 18, 1990,
between Port of Bellingham and Sumas Energy, Inc.(a)
10.7.7 -- First Amendment to Industrial Park Lease Agreement, dated as
of July 16, 1991, between Port of Bellingham, Sumas Energy,
Inc., and Sumas Cogeneration Company, L.P.(a)
10.7.8 -- Second Amendment to Industrial Park Lease Agreement, dated
as of December 17, 1991, between Port of Bellingham and
Sumas Cogeneration Company, L.P.(a)
10.7.9 -- Amended and Restated Cogeneration Lease, dated as of
December 1, 1990, between the State of California and O.L.S.
Energy-Agnews.(a)
10.8 -- General
10.8.1 -- Limited Partnership Agreement of Sumas Cogeneration Company,
L.P., dated as of August 28, 1991, between Sumas Energy,
Inc. and Whatcom Cogeneration Partners, L.P.(a)
10.8.2 -- First Amendment to Limited Partnership Agreement of Sumas
Cogeneration Company, L.P., dated as of January 30, 1992,
between Whatcom Cogeneration Partners, L.P. and Sumas
Energy, Inc.(a)
</TABLE>
48
<PAGE> 51
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.8.3 -- Second Amendment to Limited Partnership Agreement of Sumas
Cogeneration Company, L.P., dated as of May 24, 1993,
between Whatcom Cogeneration Partners, L.P. and Sumas
Energy, Inc.(a)
10.8.4 -- Second Amended and Restated Shareholders' Agreement, dated
as of October 22, 1993, among GATX Capital Corporation,
Calpine Agnews, Inc., JGS-Agnews, Inc., and
GATX/Calpine-Agnews, Inc.(a)
10.8.5 -- Amended and Restated Reimbursement Agreement, dated October
22, 1993, between GATX Capital Corporation, Calpine Agnews,
Inc., JGS-Agnews, Inc., GATX/Calpine Agnews, Inc., and
O.L.S. Energy-Agnews, Inc.(a)
10.8.6 -- Amended and Restated Limited Partnership Agreement of
Geothermal Energy Partners Ltd., L.P., dated as of May 19,
1989, between Western Geothermal Company, L.P., Sonoma
Geothermal Company, L.P., and Cloverdale Geothermal
Partners, L.P.(a)
10.8.7 -- Assignment and Security Agreement, dated as of January 10,
1990, between O.L.S.Energy-Agnews and Credit Suisse.(a)
10.8.8 -- Pledge Agreement, dated as of January 10, 1990, between
GATX/Calpine-Agnews, Inc., and Credit Suisse.(a)
10.8.9 -- Equity Support Agreement, dated as of January 10, 1990,
between Calpine Corporation and Credit Suisse.(a)
10.8.10 -- Assignment and Security Agreement, dated as of December 1,
1990, between O.L.S. Energy-Agnews and Meridian Trust
Company of California.(a)
10.8.11 -- First Amended and Restated Limited Partner Pledge and
Security Agreement, dated as of April 1, 1993, between
Sonoma Geothermal Partners, L.P., Healdsburg Energy Company,
L.P., Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.), Freeport-McMoRan Resource
Partners, L.P., and Meridian Trust Company of California.(a)
10.8.12 -- Management Services Agreement, dated January 1, 1995,
between Calpine Corporation and Electrowatt Ltd.(k)
10.8.13 -- Guarantee Fee Agreement, dated January 1, 1995, between
Calpine Corporation and Electrowatt Ltd.(g)
10.9.1 -- Calpine Corporation Stock Option Program and forms of
agreements thereunder.(a)
10.9.2 -- Calpine Corporation 1996 Stock Incentive Plan and forms of
agreements thereunder.(l)
10.9.3 -- Calpine Corporation Employee Stock Purchase Plan and forms
of agreements thereunder.(l)
10.10.1 -- Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright.(l)
10.10.2 -- Senior Vice President Employment Agreement between Calpine
Corporation and Ms. Ann B. Curtis.(l)
10.10.3 -- Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Lynn A. Kerby.(l)
10.10.4 -- Vice President Employment Agreement between Calpine
Corporation and Mr. Ron A.Walter.(l)
10.10.5 -- Vice President Employment Agreement between Calpine
Corporation and Mr. Robert D.Kelly.(l)
10.10.6 -- First Amended and Restated Consulting Contract between
Calpine Corporation and Mr. George J. Stathakis.(l)
</TABLE>
49
<PAGE> 52
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.11 -- Form of Indemnification Agreement for directors and
officers. (l)
10.11.1 -- Amendment to the Steam and Electricity Service Agreement
between Cogenron Inc. and Union Carbide Corporation dated
June 12, 1985.*
10.11.2 -- Ground Lease Agreement, between Union Carbide Corporation
and Northern Cogneration One Company dated January 1, 1986
in Texas City, Texas.*
10.11.3 -- Stock Purchase Agreement Among Gas Energy Inc., Gas Energy
Cogeneration Inc. Calpine Eastern Corporation and Calpine
Corporation dated August 22, 1997.*
10.11.4 -- First Amendment to the Stock Purchase Agreement Among Gas
Energy, Inc., Gas Cogernation Inc., The Brooklyn Union Gas
Company and Calpine Eastern Corporation and Calpine
Corporation dated August 22, 1997; as amended on December
19, 1997.*
10.11.5 -- Amended and Restated Congenerated Electricity Sale and
Purchase Agreement by and between Cogenron Inc., and Texas
Utilities Electric Company dated June 12, 1985; as
previously amended, and as amended and restated on December
29, 1997.*
10.11.6 -- Agreement for the Purchase of Electrical Power and Energy
between Capital Congernation Company, Ltd. and Texas-New
Mexico Power Company Power Agreement.*
21.1 -- Subsidiaries of the Company.(m)
27.0 -- Financial Data Schedule.*
</TABLE>
- ---------------
(a) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Current Report on Form 8-K dated
September 9, 1994 and filed on September 26, 1994.
(c) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated September 30, 1994 and filed on November 14, 1994.
(d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1994 and filed on March 29, 1995.
(e) Incorporated by reference to Registrant's Current Report on Form 8-K dated
April 21, 1995 and filed on May 5, 1995.
(f) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1995 and filed on May 12, 1995.
(g) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1995 and filed on August 14, 1995.
(h) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated September 30, 1995 and filed on November 14, 1995.
(i) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1995 and filed on March 29, 1996.
(j) Incorporated by reference to Registrant's Current Report on Form 8-K dated
May 1, 1996 and filed on May 14, 1996.
(k) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1996 and filed on May 15, 1996.
(l) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 333-07497).
(m) Incorporated by reference to Registrant's Current Report on Form 8-K dated
August 29, 1996 and filed on September 13, 1996.
50
<PAGE> 53
(n) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1996, filed on March 27, 1996.
* Filed herewith.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the period from October 1, 1997 to
December 31, 1997.
51
<PAGE> 54
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned thereunto duly authorized.
Date: April 1, 1998 CALPINE CORPORATION
By /s/ ANN B. CURTIS
------------------------------------
Ann B. Curtis
Senior Vice President and
Director (Principal Financial
Officer)
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS:
That the undersigned officers and directors of Calpine Corporation do
hereby constitute and appoint Peter Cartwright and Ann B.Curtis, and each of
them, the lawful attorney and agent or attorneys and agents with power and
authority to do any and all acts and things and to execute any and all
instruments which said attorneys and agents, or either of them, determine may be
necessary or advisable or required to enable Calpine Corporation to comply with
the Securities and Exchange Act of 1934, as amended, and any rules or
regulations or requirements of the Securities and Exchange Commission in
connection with this Form 10-K Annual Report. Without limiting the generality of
the foregoing power and authority, the powers granted include the power and
authority to sign the names of the undersigned officers and directors in the
capacities indicated below to this Form 10-K Annual Report or amendments or
supplements thereto, and each of the undersigned hereby ratifies and confirms
all that said attorneys and agents, or either of them, shall do or cause to be
done by virtue hereof. This Power of Attorney may be signed in several
counterparts.
IN WITNESS WHEREOF, each of the undersigned has executed this Power of
Attorney as of the date indicated opposite the name.
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ PETER CARTWRIGHT President, Chief Executive March 6, 1998
- -------------------------------------- Officer and Chairman of the Board
Peter Cartwright (Principal Executive Officer)
/s/ ANN B. CURTIS Senior Vice President and March 6, 1998
- -------------------------------------- Director (Principal Financial Officer)
Ann B. Curtis
/s/ JEFFREY E. GARTEN Director March 6, 1998
- --------------------------------------
Jeffrey E. Garten
/s/ SUSAN C. SCHWAB Director March 6, 1998
- --------------------------------------
Susan C. Schwab
/s/ GEORGE J. STATHAKIS Director March 6, 1998
- --------------------------------------
George J. Stathakis
/s/ JOHN O. WILSON Director March 6, 1998
- --------------------------------------
John O. Wilson
/s/ ORVILLE WRIGHT Director March 6, 1998
- --------------------------------------
V. Orville Wright
/s/ GLORIA S. GEE Controller (Principal Accounting March 6, 1998
- -------------------------------------- Officer)
Gloria S. Gee
</TABLE>
52
<PAGE> 55
CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND OTHER INFORMATION
DECEMBER 31, 1997
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
CALPINE CORPORATION AND SUBSIDIARIES
Selected Consolidated Financial Data........................ F-2
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. F-4
Report of Independent Public Accountants.................... F-13
Consolidated Balance Sheets December 31, 1997 and 1996...... F-14
Consolidated Statements of Operations for the Years Ended
December 31, 1997, 1996 and 1995.......................... F-15
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1997, 1996 and 1995.............. F-16
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995.......................... F-17
Notes to Consolidated Financial Statements for the Years
Ended December 31, 1997, 1996 and 1995.................... F-18
CALPINE CORPORATION
Report of Independent Public Accountants.................... F-43
Schedule I: Condensed Financial Information of Registrant
Balance Sheets, December 31, 1997 and 1996................ F-44
Condensed Statements of Operations for the Years Ended
December 31, 1997, 1996 and 1995....................... F-45
Condensed Statements of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995....................... F-46
Notes to Condensed Financial Statements for
December 31, 1997...................................... F-47
Schedule II: Valuation and Qualifying Accounts.............. F-52
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Independent Auditor's Report................................ F-53
Consolidated Balance Sheets, December 31, 1997 and 1996..... F-54
Consolidated Statement of Income for the Years Ended
December 31, 1997, 1996 and 1995.......................... F-55
Consolidated Statement of Changes in Partners' Equity for
the Years Ended
December 31, 1997, 1996 and 1995.......................... F-56
Consolidated Statement of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995.......................... F-57
Notes to Consolidated Financial Statements for the Year
Ended December 31, 1997................................... F-58
</TABLE>
F-1
<PAGE> 56
CALPINE CORPORATION AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT RATIO DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1993 1994 1995 1996 1997
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales................. $ 53,000 $ 90,295 $ 127,799 $ 199,464 $ 237,277
Service contract revenue from related
parties.................................. 16,896 7,221 7,153 6,455 10,177
Income (loss) from unconsolidated
investments in power projects............ 19 (2,754) (2,854) 6,537 15,819
Interest income on loans to power
projects................................. -- -- -- 2,098 13,048
---------- ---------- ---------- ---------- ----------
Total revenue....................... 69,915 94,762 132,098 214,554 276,321
Cost of revenue............................... 42,501 52,845 77,388 129,200 153,308
---------- ---------- ---------- ---------- ----------
Gross profit.................................. 27,414 41,917 54,710 85,354 123,013
Project development expenses.................. 1,280 1,784 3,087 3,867 7,537
General and administrative expenses........... 5,080 7,323 8,937 14,696 18,289
Provision for write-off of project development
costs....................................... -- 1,038 -- -- --
---------- ---------- ---------- ---------- ----------
Income from operations...................... 21,054 31,772 42,686 66,791 97,187
Interest expense.............................. 13,825 23,886 32,154 45,294 61,466
Interest income............................... (693) (1,058) (1,555) (8,604) (14,285)
Other (income) expense........................ (440) (930) (340) 2,345 (3,153)
---------- ---------- ---------- ---------- ----------
Income before provision for income taxes and
cumulative effect of change in accounting
principle................................ 8,362 9,874 12,427 27,756 53,159
Provision for income taxes.................... 4,195 3,853 5,049 9,064 18,460
---------- ---------- ---------- ---------- ----------
Income before cumulative effect of change in
accounting principle..................... 4,167 6,021 7,378 18,692 34,699
Cumulative effect of adoption of SFAS No.
109......................................... (413) -- -- -- --
---------- ---------- ---------- ---------- ----------
Net income.................................. $ 3,754 $ 6,021 $ 7,378 $ 18,692 $ 34,699
========== ========== ========== ========== ==========
Basic earnings per common share(1)
Weighted average shares of common stock
outstanding.............................. 10,388 10,388 10,388 12,903 19,946
Basic earnings per common share............. $ 0.36 $ 0.58 $ 0.71 $ 1.45 $ 1.74
Diluted earnings per common share(1)..........
Weighted average shares of common stock
outstanding.............................. 10,879 10,921 10,957 14,879 21,016
Diluted earnings per common share........... $ 0.35 $ 0.55 $ 0.67 $ 1.26 $ 1.65
OTHER FINANCIAL DATA AND RATIOS:
Depreciation and amortization................. $ 12,540 $ 21,580 $ 26,896 $ 40,551 $ 48,935
EBITDA(2)..................................... $ 42,370 $ 53,707 $ 69,515 $ 117,379 $ 172,616
EBITDA to Consolidated Interest Expense(3).... 2.98x 2.23x 2.11x 2.41x 2.60x
Total debt to EBITDA.......................... 6.24x 6.23x 5.87x 5.12x 4.96x
Ratio of earnings to fixed charges(4)......... 2.09x 1.52x 1.46x 1.45x 1.64x
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
--------------------------------------------------------------
1993 1994 1995 1996 1997
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET
Cash and cash equivalents..................... $ 6,166 $ 22,527 $ 21,810 $ 95,970 $ 48,513
Property, plant and equipment, net............ 251,070 335,453 447,751 648,208 719,721
Total assets.................................. 302,256 421,372 554,531 1,031,397 1,380,956
Total liabilities............................. 288,827 402,723 529,304 828,270 1,141,000
Total stockholders' equity.................... 13,429 18,649 25,227 203,127 239,956
</TABLE>
(The information contained in the Selected Consolidated Financial Data is
derived from the audited consolidated financial statements of Calpine
Corporation and Subsidiaries.)
(See footnotes on next page)
F-2
<PAGE> 57
- ---------------
(1) In 1997, the Company adopted Statement of Financial Accounting Standards
("SFAS") No. 128, "Earnings per Share," and subsequently, in February 1998,
Staff Accounting Bulletin ("SAB") No. 98 on Computations of Earnings per
Share. In accordance with SFAS No. 128, basic earnings per common share for
all periods was computed by dividing net income by the weighted average
shares of common stock outstanding during the year. Diluted earnings per
common share for all periods was also computed in conformance with SFAS No.
128 by dividing net income by the weighted average shares of common stock
outstanding during the year and the additional number of shares that would
have been outstanding during the year if the Company's dilutive potential
shares had been issued. The treasury stock method was used to calculate the
potential number of dilutive shares associated with the Company's
outstanding stock options (see Note 2 of Notes to Consolidated Financial
Statements).
(2) EBITDA is defined as income from operations plus depreciation, capitalized
interest, other income, non-cash charges and cash received from investments
in power projects, reduced by the income from unconsolidated investments in
power projects. EBITDA is presented not as a measure of operating results,
but rather as a measure of the Company's ability to service debt. EBITDA
should not be construed as an alternative to either (i) income from
operations (determined in accordance with generally accepted accounting
principles) or (ii) cash flows from operating activities (determined in
accordance with generally accepted accounting principles).
(3) Consolidated Interest Expense is defined as total interest expense plus
one-third of all operating lease obligations, capitalized interest,
dividends paid in respect of preferred stock and cash contributions to any
employee stock ownership plan used to pay interest on loans incurred to
purchase capital stock of the Company.
(4) Earnings are defined as income before provision for taxes, extraordinary
item and cumulative effect of change in accounting principle plus cash
received from investments in power projects and fixed charges reduced by the
equity in income from investments in power projects and capitalized
interest. Fixed charges consist of interest expense, capitalized interest,
amortization of debt issuance costs and the portion of rental expenses
representative of the interest expense component.
F-3
<PAGE> 58
CALPINE CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Except for historical financial information contained herein, the matters
discussed in this annual report may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding the intent, belief or current
expectations of the Company and its management. Prospective investors are
cautioned that any such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties; actual results
could differ materially from those indicated by such forward-looking statements.
Among the important factors that could cause actual results to differ materially
from those indicated by such forward-looking statements are: (i) that the
information is of a preliminary nature and may be subject to further adjustment,
(ii) the possible unavailability of financing, (iii) risks related to the
development, acquisition and operation of power plants, (iv) the impact of
avoided cost pricing, energy price fluctuations and gas price increases, (v) the
impact of curtailment, (vi) the seasonal nature of the Company's business, (vii)
start-up risks, (viii) general operating risks, (ix) the dependence on third
parties, (x) risks associated with international investments, (xi) risks
associated with the power marketing business, (xii) changes in government
regulation, (xiii) the availability of natural gas, (xiv) the effects of
competition, (xv) the dependence on senior management, (xvi) volatility in the
Company's stock price, (xvii) fluctuations in quarterly results and seasonality,
and (xviii) other risks identified from time to time in the Company's reports
and registration statements filed with the Securities and Exchange Commission.
GENERAL
Calpine Corporation ("Calpine") a Delaware corporation, and subsidiaries
(collectively, the "Company") is engaged in the acquisition, development,
ownership and operation of power generation facilities and the sale of
electricity and steam principally in the United States. The Company currently
has interests in 23 power plants and steam fields, having an aggregate capacity
of 2,613 megawatts. The Company currently sells electricity and steam to 16
utility and other customers, principally under long term power and steam sales
agreements, generated by power generation facilities located in six states and
Mexico. In addition, the Company has a 240 megawatt gas-fired power plant
currently under construction in Pasadena, Texas and an investment in a 169
megawatt gas-fired power plant currently under construction in Dighton,
Massachusetts. Since its inception in 1984, the Company has developed
substantial expertise in all aspects of electric power generation. The Company's
vertical integration has resulted in significant growth in recent years as the
Company has applied its extensive engineering, construction management,
operations, fuel management and financing capabilities to successfully implement
its acquisition and development program. The Company's strategy is to capitalize
on opportunities in the power market through an ongoing program to acquire,
develop, own and operate electric power generation facilities, as well as
marketing power and energy services to utilities and other end users.
The Company's net interest in power generation facilities has increased
from 297 megawatts in 1992 to 1981 megawatts at December 31, 1997, including the
power plants currently under construction. Total assets have increased from
$55.4 million as of December 31, 1992 to $1.4 billion as of December 31, 1997.
The Company's revenue has increased to $276.3 million for 1997, representing a
5-year compound annual growth rate of 48% since 1992. The Company's EBITDA (see
Selected Consolidated Financial Data) for 1997 increased to $172.6 million from
$9.9 million in 1992, representing a 5-year compound annual growth rate of 77%.
In January 1995, the Company purchased the working interest in certain of
the geothermal properties at the Pacific Gas & Electric Company ("PG&E") Unit 13
and Unit 16 Steam Fields from a third party for a purchase price of $6.75
million. On April 21, 1995, the Company acquired the stock of certain companies
that own 100% of the Greenleaf 1 and 2 Power Plants, consisting of two 49.5
megawatt gas-fired cogeneration facilities, for an adjusted purchase price of
$81.5 million. On June 29, 1995, the Company acquired the operating lease for
the Watsonville Power Plant, a 28.5 megawatt gas-fired cogeneration facility,
for a
F-4
<PAGE> 59
purchase price of $900,000. On November 17, 1995, the Company entered into a
series of agreements to invest up to $20.0 million in the Cerro Prieto Steam
Fields.
In April 1996, the Company entered into a lease transaction for the King
City Power Plant, a 120 megawatt gas-fired cogeneration facility, which required
an investment of $108.3 million, primarily related to the collateral fund
requirements. On August 29, 1996, the Company acquired the Gilroy Power Plant, a
120 megawatt gas-fired cogeneration facility, for a purchase price of $125.0
million plus certain contingent consideration, which the Company currently
estimates will amount to approximately $24.1 million, of which $12.5 million has
been paid as of December 31, 1997.
On January 31, 1997, the Company paid approximately $7.1 million to acquire
the stock of Montis Niger, Inc. (subsequently renamed Calpine Gas Company).
Calpine Gas Company has 8.1 billion cubic feet of estimated proven gas reserves
and an 80-mile pipeline system which provide gas to the Company's Greenleaf 1
and 2 Power Plants.
In February 1997, the Company commenced construction of the Pasadena Power
Plant, a 240 megawatt gas-fired cogeneration facility at the Phillips Houston
Chemical Complex ("HCC") located in Pasadena, Texas. The Company has entered
into an agreement to supply HCC with approximately 90 megawatts of electricity
(see Note 3 of Notes to Consolidated Financial Statements), with the remainder
of available electricity output to be sold into the competitive market. The
Pasadena Power Plant is the first merchant power plant to be financed with
non-recourse project financing and is scheduled to be operational in July 1998.
On June 23, 1997, the Company completed the acquisition of a 50% equity
interest in two gas-fired cogeneration facilities, the 450 megawatt Texas City
Power Plant and the 377 megawatt Clear Lake Power Plant, for an aggregate
purchase price of $35.4 million. As a part of that acquisition, the Company
entered into a $125.0 million non-recourse project financing agreement with The
Bank of Nova Scotia, the proceeds of which were utilized for the acquisition of
the 50% equity interest and the purchase of $155.6 million of outstanding
non-recourse project financing associated with the Texas City and Clear Lake
Power Plants.
On October 9, 1997, the Company completed the acquisition of 50% interests
in the Gordonsville Power Plant, a 240 megawatt gas-fired cogeneration facility
located in Gordonsville, Virginia, and the Auburndale Power Plant, a 150
megawatt gas-fired cogeneration facility located in Auburndale, Florida, for an
aggregate purchase price of $42.4 million.
On October 10, 1997, the Company entered into agreements with Energy
Management Inc. to invest in the development of two merchant power plants,
including the 169 megawatt gas-fired combined-cycle Dighton Power Plant to be
located in Dighton, Massachusetts, and the 265 megawatt gas-fired combined-cycle
Tiverton Power Plant to be located in Tiverton, Rhode Island. In October 1997,
the Company invested $16.0 million in the Dighton Power Plant (see Note 3 of
Notes to Consolidated Financial Statements). The Company intends to invest up to
$42.0 million of equity in the development of the Tiverton Power Plant. There
can be no assurances that the Dighton or Tiverton Power Plants will be
successfully developed.
On December 19, 1997, the Company completed the acquisition of 100% of the
capital stock of Gas Energy, Inc. ("GEI") and Gas Energy Cogeneration Inc.
("GECI") from The Brooklyn Union Gas Company for an aggregate purchase price of
$100.9 million, subject to final adjustments. GEI and GECI indirectly own (i) a
50% general partnership interest in the Kennedy International Airport Power
Plant, a 107 megawatt gas-fired cogeneration facility located at the John F.
Kennedy International Airport in Queens, New York, (ii) a 50% general
partnership interest in the Stony Brook Power Plant, a 40 megawatt gas-fired
cogeneration facility located on the campus of the State University of New York
in Stony Brook, New York, (iii) a 45% general partnership interest in the
Bethpage Power Plant, a 57 megawatt gas-fired cogeneration facility located in
Bethpage, New York, (iv) an 11.36% limited partnership interest in the Lockport
Power Plant, a 184 megawatt gas-fired cogeneration facility located in Lockport,
New York, and (v) a 100% interest in three fuel management contracts.
On February 5, 1998, the Company acquired the remaining 55% interest in,
and assumed operations and maintenance of, the Bethpage Power Plant. The Company
purchased the remaining interests for approximately $4.6 million.
F-5
<PAGE> 60
On February 18, 1998, the Company announced that it had entered into
exclusive negotiations to acquire a 70 megawatt gas-fired power plant and
natural gas pipeline system from The Dow Chemical Company located in Pittsburg,
California. There can be no assurance that the Company will successfully
complete this acquisition.
Each of the Company's power plants produces electricity for sale to a
utility or other third party purchasers. Thermal energy produced by the
gas-fired cogeneration facilities is sold to governmental and industrial users,
and steam produced by the geothermal steam fields is sold to utility-owned power
plants. The electricity, thermal energy and steam generated by these facilities
are typically sold pursuant to long-term, take-and-pay power or steam sales
agreements, generally having original terms of 20 or 30 years.
PG&E pays a fixed price for each unit of electrical energy according to
schedules set forth in the long-term power sales agreements for Bear Canyon (20
megawatts) and West Ford Flat (27 megawatts) Power Plants. The fixed price
periods under these power sales agreements expire in September and December
1998, respectively. After the fixed price periods expire, while the basis for
the capacity and capacity bonus payments under these power sales agreements
remains the same, the energy payments adjust to interim short-run avoided cost
("SRAC"), which is calculated pursuant to the methodology approved by the
California Public Utilities Commission ("CPUC") on December 9, 1996, and will
continue at SRAC until the independent power exchange has commenced operations
and is functioning properly. The independent power exchange is currently
scheduled to commence operations on April 1, 1998. Thereafter, SRAC will
eventually become the energy-clearing price of the independent power exchange.
During 1997, SRAC averaged approximately 2.94c per kilowatt-hour. As a result,
while SRAC does not affect capacity payments under the power sales agreements,
the Company's energy revenue under these power sales agreements is expected to
be materially reduced at the expiration of the fixed price period. Such
reduction may have a material adverse effect on the Company's results of
operations. The Company expects the forecasted decline in energy revenues will
be mitigated by decreased royalty expenses and planned operating cost reductions
at the facilities. The Company expects to continue its strategy of replacing
decreased revenues through its acquisition and development program. In addition,
prices paid for the steam delivered by the Company's steam fields are based on a
formula that partially reflects the price levels of nuclear and fossil fuels,
and, therefore, a reduction in the price levels of such fuels may reduce revenue
under the steam sales agreements for the steam fields.
Certain of the Company's power and steam sales agreements contain
curtailment provisions under which the purchasers of energy or steam are
entitled to reduce the number of hours of energy or amount of steam purchased
thereunder. For the year ended December 31, 1996, certain of the Company's power
generation facilities experienced maximum curtailment primarily as a result of
low gas prices and a high degree of precipitation during the period, which
resulted in high levels of energy generation by hydroelectric power plants that
supply electricity. For the year ended December 31, 1997, such plants
experienced a reduced amount of curtailment compared to the same period in 1996.
Due to an amendment to certain of the power sales agreements executed in May
1997, the Company currently does not expect curtailment during the remainder of
the terms of the power sales agreements for these power plants.
Many states are implementing or considering regulatory initiatives designed
to increase competition in the domestic power generation industry. In December
1995, the CPUC issued an electric industry restructuring decision, which
envisioned commencement of deregulation and implementation of customer choice of
electricity supplier by January 1, 1998. Legislation implementing this decision
was adopted in September 1996. The CPUC subsequently extended the implementation
date to April 1, 1998. As part of its policy decision, the CPUC indicated that
power sales agreements of existing qualifying facilities would be honored. The
Company cannot predict the final form or timing of the proposed restructuring
and the impact, if any, that such restructuring would have on the Company's
existing business or results of operations. The Company believes that any such
restructuring would not have a material effect on its power sales agreements
and, accordingly, believes that its existing business and results of operations
would not be materially adversely affected, although there can be no assurance
in this regard.
F-6
<PAGE> 61
SELECTED OPERATING INFORMATION
Set forth below is certain selected operating information for the power
plants and steam fields, for which results are consolidated in the Company's
Consolidated Statements of Operations. The information set forth under power
plants consists of the results for the West Ford Flat Power Plant, the Bear
Canyon Power Plant, the Greenleaf 1 and 2 Power Plants since their acquisitions
on April 21, 1995, the Watsonville Power Plant since the acquisition of the
lease on June 29, 1995, the King City Power Plant since the effective date of
the lease on May 2, 1996, and the Gilroy Power Plant since its acquisition on
August 29, 1996. The information set forth under steam fields consists of the
results for the PG&E Unit 13 and Unit 16 Steam Fields, the SMUDGEO #1 Steam
Fields and, for 1994 through 1997, the Thermal Power Company Steam Fields since
the acquisition of Thermal Power Company ("TPC") on September 9, 1994. The
information provided for the other interest included under steam revenue prior
to 1995 represents revenue attributable to a working interest that was held by a
third party in the PG&E Unit 13 and Unit 16 Steam Fields. In January 1995, the
Company purchased this working interest. Prior to the Company's acquisition of
the remaining interest in the Bear Canyon and West Ford Flat Power Plants, the
PG&E Unit 13 and Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields on April
19, 1993, the Company's revenue from these facilities was accounted for under
the equity method and, therefore, does not represent the actual revenue of the
Company from these facilities for the periods set forth below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1993 1994 1995 1996 1997
---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
POWER PLANTS:
Electricity revenue (1):
Energy..................... $ 37,088 $ 45,912 $ 54,886 $ 93,851 $ 110,879
Capacity................... $ 7,834 $ 7,967 $ 30,485 $ 65,064 $ 84,296
Megawatt hours produced.... 378,035 447,177 1,033,566 1,985,404 2,158,008
Average energy price per
kilowatt hour(2)........ 9.811c 10.267c 5.310c 4.727c 5.138c
STEAM FIELDS:
Steam revenue:
Calpine.................... $ 31,066 $ 32,631 $ 39,669 $ 40,549 $ 42,102
Other interest............. $ 2,143 $ 2,051 $ -- $ -- $ --
Megawatt hours produced.... 2,014,758 2,156,492 2,415,059 2,528,874 2,641,422
Average price per kilowatt
hour.................... 1.648c 1.608c 1.643c 1.603c 1.594c
</TABLE>
- ---------------
(1) Electricity revenue is composed of fixed capacity payments, which are not
related to production, and variable energy payments, which are related to
production.
(2) Represents variable energy revenue divided by the kilowatt-hours produced.
The significant increase in capacity revenue and the accompanying decline in
average energy price per kilowatt-hour since 1994 reflects the increase in
the Company's megawatt hour production as a result of acquisitions of
gas-fired power plants by the Company.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Revenue -- Total revenue increased 29% to $276.3 million in 1997 compared
to $214.6 million in 1996. Electricity and steam sales revenue increased 19% to
$237.3 million in 1997 compared to $199.5 million in 1996. Electricity and steam
sales revenue for 1997 reflected a full year of operation at the Gilroy and King
City Power Plants which contributed to increases in electricity and steam sales
revenue in 1997 compared to 1996 of $25.4 million, and $4.3 million,
respectively. Electricity and steam sales revenue for 1997 compared to 1996 was
also $6.0 million higher at the Bear Canyon and West Ford Flat Power Plants as a
result of increased production and an increase in fixed energy prices to 13.83c
per kilowatt-hour. During 1996, the Bear Canyon and West Ford Flat Power Plants
experienced the maximum curtailment allowed under their power sales agreements
with PG&E. In May 1997, the power sales agreements for the Bear Canyon and West
Ford Flat Power Plants were modified to remove curtailment. Without such
curtailment, these plants generated an
F-7
<PAGE> 62
additional $4.2 million in revenues in 1997 as compared to 1996. In addition,
TPC also contributed $2.7 million more revenue for 1997 than 1996, primarily due
to increased steam sales under the alternative pricing agreement entered into
with PG&E in March 1996. Service contract revenue increased to $10.2 million in
1997 compared to $6.5 million in 1996. Service contract revenue during 1996
reflected a $2.8 million loss from the Company's electricity trading operations.
The increase in service contract revenue for 1997 was also attributable to $2.8
million of revenue from the Texas City and Clear Lake Power Plants, which were
acquired in June 1997. Income from unconsolidated investments in power projects
increased to $15.8 million in 1997 compared to $6.5 million during 1996. The
increase in 1997 compared to 1996 was primarily due to equity income of $6.3
million from the Company's June 1997 investment in the Texas City and Clear Lake
Power Plants (see Note 3 of Notes to Consolidated Financial Statements), and an
increase in equity income of $2.2 million from the Company's investment in Sumas
Cogeneration Company, L.P. ("Sumas") (see Note 5 of Notes to Consolidated
Financial Statements). In accordance with a power sales agreement with Puget
Sound Power and Light Company, operations at Sumas were significantly displaced
from February to July 1997, and, in exchange, the Sumas Power Plant received a
higher price for energy sold and certain other payments. In addition, the
partnership agreement governing Sumas was amended in September 1997 to increase
the Company's percentage of distributions. Interest income on loans to power
projects increased to $13.0 million in 1997 compared to $2.1 million in 1996.
The increase was primarily related to interest income on the loans made by
Calpine Finance Company, a wholly-owned subsidiary of the Company, to the Texas
City and Clear Lake Power Plants, and to interest income on the loans to the
sole shareholder of Sumas Energy, Inc., the Company's partner in Sumas (see Note
6 of Notes to Consolidated Financial Statements).
Cost of revenue -- Cost of revenue increased 19% to $153.3 million in 1997
compared to $129.2 million in 1996. Plant operating, depreciation, and operating
lease expenses at the Gilroy and King City Power Plants for 1997 reflected a
full year of operations, which contributed to increases in cost of revenue in
1997 compared to 1996 of $13.0 million and $8.3 million, respectively.
Project development expenses -- Project development expenses increased 92%
to $7.5 million in 1997 compared to $3.9 million in 1996, due primarily to
expanded acquisition and development activities.
General and administrative expenses -- General and administrative expenses
increased 24% to $18.3 million in 1997 compared to $14.7 million in 1996. The
increases were primarily due to additional personnel and related expenses
necessary to support the Company's expanding operations.
Interest expense -- Interest expense increased 36% to $61.5 million in 1997
from $45.3 million in 1996. The increase was attributable to: (i) $10.8 million
of interest expense related to the 8 3/4% Senior Notes Due 2007 issued in July
and September 1997, (ii) a $7.3 million increase in interest expense related to
the 10 1/2% Senior Notes Due 2006 issued May 1996, (iii) a $6.4 million increase
in interest expense on debt related to the Gilroy Power Plant acquired in August
1996 and (iv) $5.4 million of interest expense on debt related to the
acquisition of the Texas City and Clear Lake Power Plants. These increases were
offset by $6.2 million of interest capitalized for the development and
construction of power plants, and a $7.6 million decrease in interest expense at
Calpine Geysers Company, L.P. ("CGC") and TPC due to repayment of debt.
Interest income -- Interest income increased 66% to $14.3 million for 1997
compared with $8.6 million for 1996. Interest income earned on collateral
securities purchased in April 1996 in connection with the King City Power Plant
contributed to an increase in interest income of $1.2 million in 1997 as
compared to 1996. In addition, higher cash and cash equivalent balances
resulting from the issuance of the 8 3/4% Senior Notes Due 2007 during 1997
resulted in higher interest income for 1997 as compared to 1996.
Other income, net -- Other income, net, increased to $3.2 million for 1997
compared with expense of $2.3 million for 1996. In 1997, the Company recorded a
$1.1 million gain on the sale of a note receivable (see Note 6 of Notes to
Consolidated Financial Statements) and received a refund of $961,000 from PG&E.
In 1996, the Company recorded a $3.7 million loss for uncollectible amounts
related to an acquisition project.
Provision for income taxes -- The effective rate for the income tax
provision was approximately 35% in 1997 and 33% in 1996. The reductions from the
statutory tax rate were primarily due to depletion in excess of
F-8
<PAGE> 63
tax basis benefits at the Company's geothermal facilities, a decrease in the
California taxes paid due to the Company's expansion into states other than
California, and a revision of prior years' tax estimates.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
Revenue -- Total revenue increased 62% to $214.6 million in 1996 compared
to $132.1 million in 1995. Electricity and steam sales revenue increased 56% to
$199.5 million in 1996 compared to $127.8 million in 1995. The King City and
Gilroy Power Plants contributed revenues of $41.5 million and $14.7 million,
respectively, to electricity and steam revenues during 1996. Revenue for 1996
also reflected a full year of operation at the Greenleaf 1 and 2 Power Plants
and the Watsonville Power Plant, which contributed to increases in electricity
and steam revenues in 1996 compared to 1995 of $9.1 million and $4.7 million,
respectively. During 1996 and 1995, the Company experienced the maximum
curtailment allowed under the power sales agreements with PG&E for the Bear
Canyon and West Ford Flat Power Plants. Without such curtailment, the Bear
Canyon and West Ford Flat Power Plants would have generated an additional $5.2
million and $5.7 million of revenue in 1996 and 1995, respectively. Service
contract revenue decreased to $6.5 million in 1996 compared to $7.2 million in
1995, reflecting a $2.8 million loss related to the Company's electricity
trading operations, offset by increased revenue during 1996 related to overhauls
at the Aidlin and Agnews Power Plants, and to technical services performed for
the Cerro Prieto project. Income from unconsolidated investments in power
projects increased to $6.5 million in 1996 compared to losses of $2.9 million
during 1995. The increase is primarily attributable to $6.4 million of equity
income generated by the Company's investment in Sumas during 1996 compared to a
$3.0 million loss in 1995. The increase in Sumas' profitability during 1996 is
primarily attributable to a contractual increase in the energy price in
accordance with the power sales agreement with Puget Sound Power & Light
Company. Interest income on loans to power projects was $2.1 million in 1996 as
a result of the recognition of interest income on loans to the sole shareholder
of the general partner in Sumas.
Cost of revenue -- Cost of revenue increased 67% to $129.2 million in 1996
as compared to $77.4 million in 1995. The increase was primarily due to plant
operating, depreciation, and operating lease expenses attributable to: (i) a
full year of operation during 1996 at the Greenleaf 1 and 2 Power Plants, which
were purchased on April 21, 1995, (ii) a full year of operation during 1996 at
the Watsonville Power Plant, for which the Company acquired the operating lease
on June 29, 1995, (iii) operations at the King City Power Plant subsequent to
May 2, 1996, and (iv) operations at the Gilroy Power Plant subsequent to
acquisition on August 29, 1996. Cost of revenue also increased due to service
contract expenses related to the Cerro Prieto Steam Fields, partially offset by
lower operating expenses at the Company's other existing power generation
facilities and steam fields.
Project development expenses -- Project development expenses increased to
$3.9 million in 1996 compared to $3.1 million in 1995, due to project
development activities.
General and administrative expenses -- General and administrative expenses
were $14.7 million in 1996 compared to $8.9 million in 1995. The increases were
primarily due to additional personnel and related expenses necessary to support
the Company's expanding operations, including the Company's power marketing
operations. The Company also incurred an employee bonus expense of $1.4 million
in September 1996 related to the initial public offering.
Interest expense -- Interest expense increased 41% to $45.3 million in 1996
from $32.2 million in 1995. Approximately $11.8 million of the increase was
attributable to interest on the Company's 10 1/2% Senior Notes Due 2006 issued
in May 1996, $2.7 million of interest expense related to the Gilroy Power Plant
acquired on August 29, 1996, and $1.6 million of higher interest expense related
to the Greenleaf 1 and 2 Power Plants acquired on April 21, 1995, offset in part
by a $3.0 million decrease in interest expense as a result of repayments of
principal on certain non-recourse project financing.
Interest income -- Interest income increased to $8.6 million for 1996
compared with $1.6 million for 1995. The increase was primarily due to $4.5
million of interest income on collateral securities purchased in connection with
the acquisition of the King City operating lease, and higher interest income for
the period due to increased cash balances as a result of sales of equity and
debt securities.
F-9
<PAGE> 64
Other income, net -- Other income, net decreased to $2.3 million of expense
for 1996 compared with $340,000 of income for 1995. The decrease was primarily
due to a $3.7 million loss for a dispute related to uncollectible amounts from
an acquisition project offset by $1.4 million in net proceeds from a development
project settlement.
Provision for income taxes -- The effective rate for the income tax
provision was approximately 33% in 1996 and 41% in 1995. In 1996, the Company
decreased its deferred income tax liability by $769,000 to reflect the change in
California's state income tax rate from 9.3% to 8.8% effective January 1, 1997.
In addition, depletion in excess of tax basis benefits at the Company's
geothermal facilities and a revision of prior years' tax estimates reduced the
Company's effective tax rate for 1996.
LIQUIDITY AND CAPITAL RESOURCES
To date, the Company has obtained cash from its operations, borrowings
under its credit facilities and other working capital lines, sale of debt and
equity, and proceeds from non-recourse project financing. The Company utilized
this cash to fund its operations, service debt obligations, fund the
acquisition, development and construction of power generation facilities,
finance capital expenditures and meet its other cash and liquidity needs.
The following table summarizes the Company's cash flow activities for the
periods indicated:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1995 1996 1997
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash flows from:
Operating activities.......... $ 26,346 $ 59,944 $ 108,461
Investing activities.......... (38,190) (330,937) (402,158)
Financing activities.......... 11,127 345,153 246,240
--------- --------- ---------
Total................. $ (717) $ 74,160 $ (47,457)
========= ========= =========
</TABLE>
Operating activities in 1997 provided $108.5 million, consisting of
approximately $34.7 million of net income from operations, $46.8 million of
depreciation and amortization, $15.1 million of deferred income taxes, $23.0
million of distributions (see Note 5 of Notes to Consolidated Financial
Statements), and a $4.7 million net decrease in operating assets and
liabilities, offset by $15.8 million of income from unconsolidated investments
in power projects.
Investing activities used $402.2 million during 1997, primarily due to
$191.0 million for the acquisition of interests in the Texas City and Clear Lake
Power Plants and the related notes receivable, $100.9 million for the
acquisition of the capital stock of GEI and GECI, $42.4 million for the
acquisition of interests in the Auburndale and Gordonsville Power Plants, $16.0
million for the investment in the Dighton Power Plant, $77.6 million of capital
expenditures related to the construction of the Pasadena Power Plant, $29.5
million of other capital expenditures, $6.2 million of interest capitalized on
construction projects, $6.0 million of capitalized project development costs,
offset by $200,000 of deferred project costs, $7.2 million of additional
investment in the Clear Lake Power Plant, $7.1 million for the acquisition of
Calpine Gas Company, offset by the receipt of $23.1 million of loan payments,
$10.0 million from the sale of loans (see Note 6 of Notes to Consolidated
Financial Statements), $5.4 million of maturities of collateral securities in
connection with the King City Power Plant and a $43.7 million decrease in
restricted cash, primarily related to the Pasadena Power Plant and CGC.
Financing activities provided $246.2 million of cash during 1997 consisting
of $125.0 million of borrowings for the acquisition of the interests in the
Texas City and Clear Lake Power Plants and the related notes receivable, $6.6
million of borrowings for contingent consideration in connection with the
acquisition of the Gilroy Power Plant and $275.0 million of proceeds from the
issuance of the 8 3/4% Senior Notes Due 2007, offset by $144.5 million in
repayment of non-recourse project financing, $7.1 million in repayment of notes
payable and $9.7 million of costs associated with financing activities.
F-10
<PAGE> 65
At December 31, 1997, cash and cash equivalents were $48.5 million and
negative working capital was $12.0 million. For the twelve months ended December
31, 1997, cash and cash equivalents decreased by $47.5 million and working
capital decreased by $102.7 million as compared to December 31, 1996.
As a developer, owner and operator of power generation facilities, the
Company may be required to make long-term commitments and investments of
substantial capital for its projects. The Company historically has financed
these capital requirements with borrowings under its credit facilities, other
lines of credit, non-recourse project financing or long-term debt.
At December 31, 1997, the Company had $105.0 million of outstanding 9 1/4%
Senior Notes Due 2004, which mature on February 1, 2004 and bear interest
payable semi-annually on February 1 and August 1 of each year. In addition, the
Company had $180.0 million of outstanding 10 1/2% Senior Notes Due 2006, which
mature on May 15, 2006 and bear interest payable semi-annually on May 15 and
November 15 of each year. During 1997, the Company issued $275.0 million of
8 3/4% Senior Notes Due 2007, which mature on July 15, 2007 and bear interest
payable semi-annually on January 15 and July 15 of each year. Under the
provisions of the applicable indentures, the Company may, under certain
circumstances, be limited in its ability to make restricted payments, as
defined, which includes dividends and certain purchases and investments, incur
additional indebtedness and engage in certain transactions.
At December 31, 1997, the Company had $192.5 million of non-recourse
project financing associated with the Greenleaf 1 and 2 Power Plants and the
Gilroy Power Plant. The annual maturities for such non-recourse project
financing are $9.6 million for 1998, $8.7 million for 1999, $10.4 million for
2000, $10.6 million for 2001, $11.1 million for 2002 and $142.1 million
thereafter.
At December 31, 1997, the Company had $103.4 million of non-recourse
borrowings from The Bank of Nova Scotia in connection with the acquisition of
the notes receivable from the Texas City and Clear Lake Power Plants. Such
borrowings mature on June 22, 1998. The Company expects to refinance such
borrowings before the maturity date.
The Company currently has a $50.0 million revolving credit agreement with a
consortium of commercial lending institutions led by The Bank of Nova Scotia,
with borrowings bearing interest at either the London Inter Bank Offering Rate
or at The Bank of Nova Scotia base rate, plus a mutually agreed margin. At
December 31, 1997, the Company had no borrowings outstanding and $9.4 million of
letters of credit outstanding under the revolving credit facility (see Note 7 of
Notes to Consolidated Financial Statements). The Bank of Nova Scotia credit
facility contains certain restrictions that limit or prohibit, among other
things, the ability of the Company or its subsidiaries to incur indebtedness,
make payments of certain indebtedness, pay dividends, make investments, engage
in transactions with affiliates, create liens, sell assets and engage in mergers
and consolidations.
The Company has a $1.2 million working capital line with a commercial
lender that may be used to fund short-term working capital commitments and
letters of credit. At December 31, 1997, the Company had no borrowings under
this working capital line and $74,000 of letters of credit outstanding.
Borrowings are at prime plus 1%.
Where appropriate, the Company may use non-recourse project financing for
new projects. The debt agreements of the Company's subsidiaries and other
affiliates governing the non-recourse project financing generally restrict their
ability to pay dividends, make distributions or otherwise transfer funds to the
Company. The dividend restrictions in such agreements generally require that,
prior to the payment of dividends, distributions or other transfers, the
subsidiary or other affiliate must provide for the payment of other obligations,
including operating expenses, debt service and reserves. However, the Company
does not believe that such restrictions will adversely affect its ability to
meet its debt obligations.
At December 31, 1997, the Company had commitments for capital expenditures
in 1998 totaling $19.8 million related to the Pasadena Power Plant (see Note 3
of Notes to Consolidated Financial Statements). The Company intends to fund
capital expenditures for the ongoing operation and development of the Company's
power generation facilities primarily through the operating cash flow of such
facilities, non-recourse project financing and corporate financing. Capital
expenditures for the twelve months ended
F-11
<PAGE> 66
December 31, 1997 of $107.1 million included $77.6 million for the construction
of the Pasadena Power Plant, $12.1 million related to the geothermal facilities,
$2.5 million related to the development of other merchant power plants and the
remaining $14.9 million at certain of the Company's gas-fired power plants.
The Company continues to pursue the acquisition and development of new
power plants. The Company expects to commit significant capital in future years
for the acquisition and development of these power plants. The Company's actual
capital expenditures may vary significantly during any year.
The Company believes that it will have sufficient liquidity from cash flow
from operations, borrowings available under the lines of credit, and working
capital to satisfy all obligations under outstanding indebtedness, to finance
anticipated capital expenditures and to fund working capital requirements
through December 31, 1998.
NEW ACCOUNTING STANDARDS
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 130, "Reporting
Comprehensive Income," which establishes standards for reporting comprehensive
income and its components (revenues, expenses, gains and losses) in financial
statements. SFAS No. 130 requires classification of other comprehensive income
in a financial statement, and the display of the accumulated balance of other
comprehensive income separately from retained earnings and additional paid-in
capital. SFAS No. 130 is effective for fiscal years beginning after December 15,
1997. The Company believes this pronouncement will not have a material effect on
its financial statements.
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information," which established standards
for reporting information about operating segments in annual financial
statements and requires that enterprises report selected information about
operating segments in interim financial reports to shareholders. SFAS No. 131
also establishes standards for related disclosures about products and services,
geographic areas and major customers. SFAS No. 131 is effective for fiscal years
beginning after December 15, 1997, although earlier application is encouraged.
The Company believes this pronouncement will not have a material effect on its
financial statements.
YEAR 2000 COMPLIANCE
To ensure that the Company's computer systems are Year 2000 compliant, the
Company has begun preparing for the Year 2000 issue. The Company has been
reviewing each of its financial and operating systems to identify those that
contain two-digit year codes. The Company is assessing the amount of programming
required to upgrade or replace each of the affected programs with the goal of
completing all relevant internal software remediation and testing by 1998, with
continuing Year 2000 compliance efforts through 1999. In addition, the Company
is actively working with all of its partnerships to assess their compliance
efforts and the Company's exposure resulting from Year 2000 issues.
Based upon current information, the Company does not anticipate costs
associated with the Year 2000 issue to have a material financial impact.
However, there can be no assurances that there will not be interruptions or
other limitations of financial and operating systems functionality or that the
Company will not incur significant costs to avoid such interruptions or
limitations. The costs incurred relating to the Year 2000 issue will be expensed
by the Company during the period in which they are incurred. The Company's
expectations about future costs associated with the Year 2000 issue are subject
to uncertainties that could cause actual results to have a greater financial
impact than currently anticipated. Factors that could influence the amount and
timing of future costs include the success of the Company in identifying systems
and programs that contain two-digit year codes, the nature and amount of
programming required to upgrade or replace each of the affected programs, the
rate and magnitude of related labor and consulting costs, and the success of the
Company's partnerships in addressing the Year 2000 issue.
F-12
<PAGE> 67
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors
of Calpine Corporation:
We have audited the accompanying consolidated balance sheets of Calpine
Corporation (a Delaware corporation) and subsidiaries as of December 31, 1997
and 1996, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1997. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We did not audit the financial statements of
Sumas Cogeneration Company, L.P. ("Sumas"), the investment in which is reflected
in the accompanying financial statements using the equity method of accounting.
The investment in Sumas represents approximately 1% of the Company's total
assets at December 31, 1996. There is no investment balance as of December 31,
1997. The Company has recorded income of $8.6 million and $6.4 million and
losses of $3.0 million representing its share of the net income or loss of Sumas
for the years ended December 31, 1997, 1996 and 1995, respectively. The
financial statements of Sumas were audited by other auditors whose report has
been furnished to us and our opinion, insofar as it relates to the amounts
included for Sumas, is based solely on the report of the other auditors.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits and the report of the other auditors provide a
reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors,
the financial statements referred to above present fairly, in all material
respects, the financial position of Calpine Corporation and subsidiaries as of
December 31, 1997 and 1996, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
February 10, 1998
(except for Note 16 as
to which the date is
February 17, 1998)
F-13
<PAGE> 68
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1997 AND 1996
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996
---------- ----------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 48,513 $ 95,970
Accounts receivable from related parties.................. 7,672 2,826
Accounts receivable....................................... 35,133 39,962
Collateral securities, current portion.................... 6,036 5,470
Loans receivable from related parties, current portion.... 30,507 --
Prepaid operating lease................................... 13,652 12,668
Inventories............................................... 6,015 5,375
Other current assets...................................... 19,050 8,171
---------- ----------
Total current assets.............................. 166,578 170,442
Property, plant and equipment, net.......................... 719,721 648,208
Investments in power projects............................... 239,160 13,936
Project development costs................................... 4,614 86
Collateral securities, net of current portion............... 87,134 89,806
Loans receivable from related parties, net of current
portion................................................... 101,304 --
Notes receivable from related parties....................... 16,053 36,143
Restricted cash............................................. 15,584 59,259
Other assets................................................ 30,808 13,517
---------- ----------
Total assets...................................... $1,380,956 $1,031,397
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and short term borrowings................... -- 6,865
Current portion of non-recourse project financing......... 112,966 30,627
Accounts payable.......................................... 30,441 18,363
Accrued payroll and related expenses...................... 4,950 3,912
Accrued interest payable.................................. 18,025 7,332
Other current liabilities................................. 12,204 12,621
---------- ----------
Total current liabilities......................... 178,586 79,720
Non-recourse project financing, net of current portion...... 182,893 278,640
Senior Notes................................................ 560,041 285,000
Deferred income taxes, net.................................. 142,050 100,385
Deferred lease incentive.................................... 71,383 74,952
Other liabilities........................................... 6,047 9,573
---------- ----------
Total liabilities................................. 1,141,000 828,270
---------- ----------
Stockholders' equity:
Common stock, $0.001 par value per share; authorized
100,000,000 shares in 1997 and 1996; issued and
outstanding 20,060,705 shares in 1997 and 19,843,400
shares in 1996......................................... 20 20
Additional paid-in capital................................ 167,542 165,412
Retained earnings......................................... 72,394 37,695
---------- ----------
Total stockholders' equity........................ 239,956 203,127
---------- ----------
Total liabilities and stockholders' equity........ $1,380,956 $1,031,397
========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-14
<PAGE> 69
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Revenue:
Electricity and steam sales.............................. $237,277 $199,464 $127,799
Service contract revenue from related parties............ 10,177 6,455 7,153
Income (loss) from unconsolidated investments in power
projects.............................................. 15,819 6,537 (2,854)
Interest income on loans to power projects............... 13,048 2,098 --
-------- -------- --------
Total revenue.................................... 276,321 214,554 132,098
-------- -------- --------
Cost of revenue:
Plant operating expenses................................. 72,366 61,894 33,162
Depreciation............................................. 47,501 39,818 26,264
Production royalties..................................... 10,803 10,793 10,574
Operating lease expenses................................. 14,031 9,295 1,542
Service contract expenses................................ 8,607 7,400 5,846
-------- -------- --------
Total cost of revenue............................ 153,308 129,200 77,388
-------- -------- --------
Gross profit............................................... 123,013 85,354 54,710
Project development expenses............................... 7,537 3,867 3,087
General and administrative expenses........................ 18,289 14,696 8,937
-------- -------- --------
Income from operations........................... 97,187 66,791 42,686
Interest expense:
Related parties.......................................... -- 894 1,663
Other.................................................... 61,466 44,400 30,491
Interest income............................................ (14,285) (8,604) (1,555)
Other (income) expense..................................... (3,153) 2,345 (340)
-------- -------- --------
Income before provision for income taxes......... 53,159 27,756 12,427
Provision for income taxes................................. 18,460 9,064 5,049
-------- -------- --------
Net income....................................... $ 34,699 $ 18,692 $ 7,378
======== ======== ========
Basic earnings per common share:
Weighted average shares of common stock outstanding...... 19,946 12,903 10,388
Basic earnings per common share.......................... $ 1.74 $ 1.45 $ 0.71
Diluted earnings per common share:
Weighted average shares of common stock outstanding...... 21,016 14,879 10,957
Diluted earnings per common share........................ $ 1.65 $ 1.26 $ 0.67
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-15
<PAGE> 70
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONAL
PREFERRED COMMON PAID IN RETAINED
STOCK STOCK CAPITAL EARNINGS TOTAL
--------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C>
Balance of 10,387,692 shares of common stock
at December 31, 1994...................... $ -- $ 10 $ 6,214 $ 12,425 $ 18,649
Dividend ($0.40 per share)................ -- -- -- (800) (800)
Net income................................ -- -- -- 7,378 7,378
-------- -------- -------- -------- --------
Balance, December 31, 1995.................. -- 10 6,214 19,003 25,227
Issuance of 5,000,000 shares of preferred
stock.................................. 50 -- 49,950 -- 50,000
Conversion of 5,000,000 shares of
preferred stock to 2,179,487 shares of
common stock........................... (50) 3 47 -- --
Issuance of 7,276,221 shares of common
stock, net............................. -- 7 109,172 -- 109,179
Tax benefit from stock options
exercised.............................. -- -- 29 -- 29
Net income................................ -- -- -- 18,692 18,692
-------- -------- -------- -------- --------
Balance, December 31, 1996.................. -- 20 165,412 37,695 203,127
Issuance of 217,305 shares of common
stock, net............................. -- -- 1,022 -- 1,022
Tax benefit from stock options exercised
and other.............................. -- -- 1,108 -- 1,108
Net income................................ -- -- -- 34,699 34,699
-------- -------- -------- -------- --------
Balance, December 31, 1997.................. $ -- $ 20 $167,542 $ 72,394 $239,956
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-16
<PAGE> 71
CALPLNE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income.......................................... $ 34,699 $ 18,692 $ 7,378
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization, net............... 46,819 36,600 25,931
Deferred income taxes, net....................... 15,082 2,028 (1,027)
(Income) loss from unconsolidated investments in
power projects................................. (15,819) (6,537) 2,854
Distributions from unconsolidated power
projects....................................... 22,950 1,274 --
Change in operating assets and liabilities:
Accounts receivable............................ 7,249 (12,652) (3,354)
Inventories.................................... (632) 256 --
Other current assets........................... (9,304) 55 (9,542)
Other assets................................... (13,203) 63 (307)
Accounts payable and accrued expenses.......... 17,464 16,818 6,847
Other liabilities.............................. 3,156 3,347 (2,434)
--------- --------- ---------
Net cash provided by operating activities... 108,461 59,944 26,346
--------- --------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment........ (107,094) (24,057) (17,434)
Acquisitions........................................ (108,671) (149,640) (14,336)
Investments in unconsolidated power projects........ (100,968) -- --
Assumption of loan receivable....................... (155,622) -- --
(Increase) decrease in notes receivable............. 33,110 (10,176) (6,348)
Investment in collateral securities................. -- (98,446) --
Maturities of collateral securities................. 5,350 2,900 --
Project development costs........................... (11,938) (5,887) (1,258)
Decrease (increase) in restricted cash.............. 43,675 (45,631) 1,186
--------- --------- ---------
Net cash used in investing activities....... (402,158) (330,937) (38,190)
--------- --------- ---------
Cash flows from financing activities:
Payment of dividends................................ -- -- (800)
Borrowings from line of credit...................... 14,300 46,861 34,851
Repayment of borrowings from line of credit......... (14,300) (66,712) (15,000)
Borrowings from non-recourse project financing...... 131,600 119,760 76,026
Repayments of non-recourse project financing........ (144,529) (84,708) (79,388)
Proceeds from notes payable and short-term
borrowings....................................... -- 45,000 2,683
Repayments of notes payable and short-term
borrowings....................................... (7,131) (46,177) (6,006)
Proceeds from issuance of Senior Notes.............. 275,000 180,000 --
Proceeds from issuance of preferred stock........... -- 50,000 --
Proceeds from issuance of common stock.............. 1,022 109,208 --
Financing costs..................................... (9,722) (8,079) (1,239)
--------- --------- ---------
Net cash provided by financing activities... 246,240 345,153 11,127
--------- --------- ---------
Net increase (decrease) in cash and cash
equivalents......................................... (47,457) 74,160 (717)
Cash and cash equivalents, beginning of period........ 95,970 21,810 22,527
--------- --------- ---------
Cash and cash equivalents, end of period.............. $ 48,513 $ 95,970 $ 21,810
========= ========= =========
Cash paid during the year for:
Interest............................................ $ 42,746 $ 43,805 $ 32,162
Income taxes........................................ $ 9,795 $ 6,947 $ 4,294
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-17
<PAGE> 72
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") is engaged in the development, acquisition,
ownership and operation of power generation facilities and the sale of
electricity and steam in the United States and selected international markets.
The Company has ownership interests in and operates gas-fired cogeneration
facilities, geothermal steam fields and geothermal power generation facilities
in northern California, Washington, Texas and various locations on the East
Coast. Each of the generation facilities produces and markets electricity for
sale to utilities and other third party purchasers. Thermal energy produced by
the gas-fired cogeneration facilities is primarily sold to governmental and
industrial users and steam produced by geothermal steam fields is sold to
utility-owned power plants. For the year ended December 31, 1997, primarily all
electricity and steam sales revenue from consolidated subsidiaries was derived
from sales to two customers in northern California (see Note 15), of which 43%
was related to geothermal activities.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The accompanying consolidated financial
statements include accounts of the Company. Wholly-owned and majority-owned
subsidiaries are consolidated. Less-than-majority-owned subsidiaries, and
subsidiaries for which control is deemed to be temporary, are accounted for
using the equity method. For equity method investments, the Company's share of
income is calculated according to the Company's equity ownership or according to
the terms of the appropriate partnership agreement (see Note 5). All significant
intercompany accounts and transactions are eliminated in consolidation. The
Company uses the proportionate consolidation method to account for Thermal Power
Company's ("TPC") 25% interest in jointly owned geothermal properties.
Use of Estimates in Preparation of Financial Statements -- The preparation
of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, and disclosure of contingent assets
and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimates. The most significant estimates with regard to these
financial statements relate to future development costs and total productive
resources of the geothermal facilities (see Property, Plant and Equipment), and
the realization of deferred income taxes (see Note 11). Additionally, the
Company believes that certain industry restructuring (see Note 16, Regulation
and CPUC Restructuring) will not have a material effect on existing power sales
agreements and, accordingly, will not have a material effect on existing
business or results of operations.
Revenue Recognition -- Revenue from electricity and steam sales is
recognized upon transmission to the customer. Revenues from contracts entered
into or acquired since May 21, 1992 are recognized at the lesser of amounts
billable under the contract or amounts recognizable at an average rate over the
term of the contract. The Company's power sales agreements related to Calpine
Geyser's Company, L.P. ("CGC") were entered into prior to May 1992. Had the
Company applied the methodology described above to the CGC power sales
agreements, the revenues recorded for the years ended December 31, 1997, 1996
and 1995, would have been approximately $20.1 million, $16.1 million, and $12.6
million less, respectively.
The Company performs operations and maintenance services for all
consolidated projects in which it has an interest, except for TPC. Revenue from
investees is recognized on these contracts when the services are performed.
Cash and Cash Equivalents -- The Company considers all highly liquid
investments with an original maturity of three months or less to be cash
equivalents. The carrying amount of these instruments approximates fair value
because of their short maturity.
F-18
<PAGE> 73
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Restricted Cash -- The Company is required to maintain cash balances that
are restricted by provisions of its debt agreements and by regulatory agencies.
The Company's debt agreements specify restrictions based on debt service
payments and drilling costs for the following year. Regulatory agencies require
cash to be restricted to ensure that funds will be available to restore property
to its original condition. Restricted cash is invested in accounts earning
market rates; therefore, the carrying value approximates fair value. Such cash
is excluded from cash and cash equivalents for the purposes of the consolidated
statements of cash flows.
Inventories -- Operating supplies are valued at the lower of cost or
market. Cost for large replacement parts is determined using the specific
identification method. For the remaining supplies, cost is determined using the
weighted average cost method.
Collateral Securities -- The Company maintains certain investments in
investment grade collateral securities which are classified as held-to-maturity
and stated at amortized cost. The investments in debt securities mature at
various dates through August 2018 in amounts equal to a portion of the King City
Power Plant lease payment (see Note 3, "King City Transaction"). The fair value
of held-to-maturity securities was determined based on the quoted market prices
at the reporting date for the securities.
The components of held-to-maturity securities by major security type as of
December 31, 1997 and 1996 are as follows (in thousands):
<TABLE>
<CAPTION>
UNREALIZED
AMORTIZED AGGREGATE HOLDING
COST FAIR VALUE GAINS
1997 --------- ---------- ----------
<S> <C> <C> <C>
Debt securities issued by the United States
government............................... $ 58,312 $ 63,174 $ 4,862
Corporate debt securities.................. 34,858 37,485 2,627
-------- -------- --------
Total............................ $ 93,170 $100,659 $ 7,489
======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
1996
<S> <C> <C> <C>
Debt securities issued by the United States
government............................... $ 54,826 $ 56,737 $ 1,911
Corporate debt securities.................. 40,450 40,499 49
-------- -------- --------
Total............................ $ 95,276 $ 97,236 $ 1,960
======== ======== ========
</TABLE>
Concentration of Credit Risk -- Financial instruments which potentially
subject the Company to concentrations of credit risk consist primarily of cash,
accounts receivable, notes receivable, and loans receivable. The Company's cash
accounts are held by seven FDIC insured banks. The Company's accounts, notes and
loans receivable are concentrated within entities engaged in the energy industry
(see Note 15), mainly within the United States, some of which are related
parties. The Company also maintains a note receivable with a company in Mexico
(see Note 6, "Calpine Vapor Inc."). The Company generally does not require
collateral for accounts receivable.
Property, Plant and Equipment, net -- Property, plant and equipment, net
are stated at cost less accumulated depreciation and amortization.
The Company capitalizes costs incurred in connection with the development
of geothermal properties, including costs of drilling wells and overhead
directly related to development activities, together with the costs of
production equipment, the related facilities and the operating power plants.
Geothermal properties include the value attributable to the geothermal resources
of CGC and all of the property, plant and equipment of TPC. Proceeds from the
sale of geothermal properties are applied against capitalized costs, with no
gain or loss recognized. At December 31, 1997 and 1996, the Company had $4.0
million of geothermal leases at Glass Mountain in northern California recorded
as property, plant and equipment, net in the accompanying
F-19
<PAGE> 74
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
consolidated balance sheets. The Company is continuing to pursue the development
of Glass Mountain, and expects to recover the cost of such leases from the
future development of the resource.
Geothermal costs, including an estimate of future development costs to be
incurred and the estimated costs to dismantle, are amortized by the units of
production method based on the estimated total productive output over the
estimated useful lives of the related steam fields. Depreciation of the
buildings and roads is computed using the straight-line method over their
estimated useful lives. It is reasonably possible that the estimate of useful
lives, total units of production or total capital costs to be amortized using
the units of production method could differ materially in the near term from the
amounts assumed in arriving at current depreciation expense. These estimates are
affected by such factors as the ability of the Company to continue selling steam
and electricity to customers at estimated prices, changes in prices of
alternative sources of energy such as hydro-generation and gas, and changes in
the regulatory environment.
Gas-fired power production facilities include the cogeneration plants and
related equipment and are stated at cost. Depreciation is recorded utilizing the
straight-line method over the estimated original useful life of up to 30 years.
The value of the above-market pricing provided in power sales agreements
acquired is recorded in property, plant and equipment, net and is amortized over
the above market pricing period in the power sales agreement with lives of 22
and 23 years. When assets are disposed of, the cost and related accumulated
depreciation are removed from the accounts, and the resulting gains or losses
are included in results of operations.
As of December 31, 1997 and 1996, the components of property, plant and
equipment, net are as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996
--------- ---------
<S> <C> <C>
Geothermal properties........................ $ 307,152 $ 297,002
Buildings, machinery and equipment........... 299,018 275,459
Power sales agreements....................... 145,957 145,957
Other assets................................. 11,629 11,555
--------- ---------
763,756 729,973
Less accumulated depreciation and
amortization............................... (148,390) (100,674)
--------- ---------
615,366 629,299
Land......................................... 754 754
Construction in progress..................... 103,601 18,155
--------- ---------
Property, plant and equipment,
net.............................. $ 719,721 $ 648,208
========= =========
</TABLE>
Construction in progress includes costs primarily attributable to the
development and construction of the Pasadena Power Plant.
Project Development Costs -- The Company capitalizes project development
costs once it is determined that it is probable that such costs will be realized
through the ultimate construction of a power plant. Generally this occurs upon
the execution of a memorandum of understanding or a letter of intent for a power
or steam sales agreement. These costs include professional services, salaries,
permits and other costs directly related to the development of a new project.
Outside services and other third party costs are capitalized for acquisition
projects. Upon the start-up of plant operations or the completion of an
acquisition, these costs are generally transferred to property, plant and
equipment, net and amortized over the estimated useful life of the project.
Capitalized project costs are charged to expense when the Company determines
that the project will not be consummated or is impaired.
F-20
<PAGE> 75
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Capitalized Interest -- The Company capitalizes interest on projects during
the construction period. For the year ended December 31, 1997, the Company
capitalized $6.2 million of interest in connection with the construction of its
power plants. No interest was capitalized prior to 1997.
Other Assets -- Other assets consist of the following at December 31, (in
thousands):
<TABLE>
<CAPTION>
1997 1996
------- -------
<S> <C> <C>
Deferred financing costs......................... $20,493 $13,396
Prepaid operating lease, long term portion....... 9,808 --
Other............................................ 507 121
------- -------
Other assets........................... $30,808 $13,517
======= =======
</TABLE>
Deferred financing costs are amortized over the term of the related
financings, which range from 12 to 180 months.
Derivative Financial Instruments -- The Company engages in activities to
manage risks associated with changes in interest rates. The Company has entered
into swap agreements to reduce exposure to interest rate fluctuations in
connection with certain debt commitments. The instruments' cash flows mirror
those of the underlying exposure. Unrealized gains and losses relating to the
instruments are being deferred over the lives of the contracts. The premiums
paid on the instruments, as measured at inception, are being amortized over
their respective lives as components of interest expense. Any gains or losses
realized upon the early termination of these instruments are deferred and
recognized in income over the remaining life of the underlying exposure. At
December 31, 1997, the Company had $239.1 million of interest rate swaps on non-
recourse project financing.
Power Marketing -- The Company, through its wholly-owned subsidiary Calpine
Power Services Company ("CPSC"), markets power and energy services to utilities,
wholesalers, and end users. CPSC provides these services by entering into
contracts to purchase or supply electricity at specified delivery points and
specified future dates. In some cases, CPSC utilizes option agreements to manage
its exposure to market fluctuations. At December 31, 1997, CPSC held option
contracts with two entities for the purchase and sale of up to 50 megawatts each
for the period from June 1, 1998 to September 30, 1998.
Net open positions may exist due to the origination of new transactions and
the Company's evaluation of changing market conditions. An open position exposes
the Company to the risk that fluctuating market prices may adversely impact its
financial position or results of operations. However, any net open positions are
actively managed. The impact of such transactions on the Company's financial
position is not necessarily indicative of the impact of price fluctuations
throughout the year. CPSC values its portfolio using the aggregate lower of cost
or market method. An allowance is recorded for net aggregate losses of the
entire portfolio resulting from the effect of market changes on net open
positions. Net gains are recognized when realized.
The Company's credit risk associated with power contracts results from the
risk of loss as a result of non-performance by counter parties. The Company
reviews and assesses counter party risk to limit any material impact to its
financial position and results of operations. The Company does not anticipate
non-performance by the counter parties. The Company sets credit limits prior to
entering into transactions and has not obtained collateral or security.
Basic and Diluted Earnings Per Share -- In 1997, the Company adopted
Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings per
Share." In February 1998, the Securities and Exchange Commission ("SEC") staff
released Staff Accounting Bulletin ("SAB") No. 98, "Computations of Earnings per
Share." SAB No. 98 revises prior SEC guidance concerning presentation of
earnings per share information for companies going public, and requires all
companies to present earnings per share for all periods
F-21
<PAGE> 76
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
for which income statement information is presented in accordance with SFAS No.
128. Basic earnings per share were computed using the weighted average number of
common shares outstanding. Diluted earnings per share were computed using the
weighted average number of common shares and the common equivalent shares that
would have been outstanding if the Company's dilutive potential shares had been
issued. The treasury stock method was used to calculate the potential number of
dilutive shares associated with the Company's outstanding stock options.
New Accounting Pronouncements -- In June 1997, the Financial Accounting
Standards Board ("FASB") issued SFAS No. 130, "Reporting Comprehensive Income,"
which establishes standards for reporting comprehensive income and its
components (revenues, expenses, gains and losses) in financial statements. SFAS
No. 130 requires classification of other comprehensive income in a financial
statement, and the display of the accumulated balance of other comprehensive
income separately from retained earnings and additional paid-in capital. SFAS
No. 130 is effective for fiscal years beginning after December 15, 1997. The
Company believes this pronouncement will not have a material effect on its
financial statements.
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This pronouncement
established standards for reporting information about operating segments in
annual financial statements and requires that enterprises report selected
information about operating segments in interim financial reports to
shareholders. SFAS No. 131 also establishes standards for related disclosures
about products and services, geographic areas and major customers. SFAS No. 131
is effective for fiscal years beginning after December 15, 1997, although
earlier application is encouraged. The Company believes this pronouncement will
not have a material effect on its financial statements.
Reclassifications -- Certain prior years' amounts in the consolidated
financial statements have been reclassified where necessary to conform to the
1997 presentation.
3. ACQUISITIONS AND INVESTMENTS
The following acquisitions and investments were consummated during the
three years ended December 31, 1997:
GREENLEAF TRANSACTION
In April 1995, the Company acquired the outstanding capital stock of
Portsmouth Leasing Corporation, LFC No. 38 Corp. and LFC No. 60 Corp.
(collectively, the "Acquired Companies") for $80.5 million. The purchase price
included a cash payment of $20.3 million and the assumption of project debt
totaling $60.2 million. In April 1996, the Company finalized the purchase price
at $81.5 million.
The Acquired Companies own 100% of the assets of two 49.5 megawatt
gas-fired cogeneration facilities Greenleaf 1 and Greenleaf 2 (collectively, the
"Greenleaf Power Plants"), located in Yuba City in northern California.
Electrical energy generated by the Greenleaf Power Plants is sold to Pacific Gas
and Electric Company ("PG&E") pursuant to two long-term power sales agreement
(expiring in 2019) at prices equal to PG&E's full short-run avoided operating
costs, adjusted annually. The power sales agreement also includes payment
provisions for firm capacity payments through 2019 for up to 49.2 megawatts on
each unit and as-delivered capacity on excess deliveries. PG&E, at its
discretion, may curtail purchases of electricity from the Greenleaf Power Plants
due to hydro-spill or uneconomic cost conditions. Thermal energy generated is
utilized by thermal hosts adjacent to the Greenleaf Power Plants.
Gas for the Greenleaf Power Plants is supplied by Calpine Gas Company (see
"Montis Niger Transaction").
F-22
<PAGE> 77
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
KING CITY TRANSACTION
In April 1996, the Company entered into a long-term operating lease with
BAF Energy, a California Limited Partnership ("BAF"), for a 120 megawatt
gas-fired cogeneration power plant located in King City, California. The power
plant generates electricity for sale to PG&E pursuant to a long-term power sales
agreement through 2019. The Company recorded the value of the above-market
pricing in the power sales agreement of $82.1 million as an asset, which is
included in property, plant and equipment, net and is being amortized over the
remaining life of the above market pricing period. The Company makes semi-annual
lease payments to BAF on February 15 and August 15, a portion of which is
supported by a $93.2 million collateral fund owned by the Company (see Note 2,
Collateral Securities). As of December 31, 1997, future rent payments are $23.8
million for 1998, $19.4 million for 1999, $20.1 million for 2000, $20.8 million
for 2001, $21.6 million for 2002, and $161.6 million thereafter. Included in the
accompanying December 31, 1997 balance sheet is approximately $23.5 million of
unamortized prepaid lease costs. The Company also recorded a deferred lease
incentive of $75.0 million at December 31, 1997 equal to the value of the
above-market payments to be received. Lease expense, net of amortization of the
deferred lease incentive, was $13.7 million and $9.1 million in 1997 and 1996,
respectively.
GILROY TRANSACTION
In August 1996, the Company acquired a 120 megawatt gas-fired cogeneration
power plant located in Gilroy, California. The cost of the Gilroy Power Plant
was $125.0 million plus certain contingent consideration, which is expected to
be $24.1 million, of which $12.5 million had been paid as of December 31, 1997.
In addition, the Company recorded the value of the above-market pricing in the
power sales agreement of $63.9 million as an asset, which is included in
property, plant and equipment, net, and is being amortized over the remaining
life of 22 years.
Electricity generated by the Gilroy Power Plant is sold to PG&E pursuant to
a long-term power sales agreement terminating in 2018. The power sales agreement
contains payment provisions for capacity and energy. The Gilroy Power Plant also
produces and sells thermal energy to ConAgra, Inc.
Pro Forma Consolidated Results
The following unaudited pro forma consolidated results for the Company give
effect to: (i) the King City Transaction and (ii) the Gilroy Transaction as if
such transactions had occurred on January 1, 1996. Unaudited pro forma
consolidated results are also provided for the effects of the above transactions
and (iii) the Watsonville operating lease acquired on June 28, 1995, and (iv)
the Greenleaf transaction, as if such had occurred on January 1, 1995 (in
thousands, except per share amount).
<TABLE>
<CAPTION>
1996 1995
-------- --------
<S> <C> <C>
Revenue...................................... $237,924 $221,447
Net income................................... $ 18,954 $ 11,288
Diluted earnings per share................... $ 1.27 $ 1.03
</TABLE>
PASADENA COGENERATION PROJECT
In December 1996, the Company entered into a development agreement with
Phillips Petroleum Company ("Phillips") to construct and operate a 240 megawatt
gas-fired cogeneration project at the Phillips Houston Chemical Complex ("HCC")
located in Pasadena, Texas. Additionally, the Company entered into an energy
sales agreement with Phillips pursuant to which Phillips will purchase all of
HCC's steam and electricity requirements of approximately 90 megawatts. It is
anticipated that the remainder of available electricity output will be sold into
the competitive market (see Note 2, Power Marketing). The Company also
F-23
<PAGE> 78
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
entered into a credit agreement with ING U.S. Capital Corporation ("ING") to
provide $151.8 million of construction financing to the project. At December 31,
1997, the Company had no borrowings against this credit agreement. In January
1998, the Company borrowed $35.9 million from ING in accordance with the terms
of the credit agreement.
MONTIS NIGER TRANSACTION
In January 1997, the Company paid approximately $7.1 million for 100% of
the stock of Montis Niger, Inc. (subsequently renamed Calpine Gas Company).
Calpine Gas Company owns gas fields with 8.1 billion cubic feet of estimated
proven gas reserves and an 80-mile pipeline system, which provides gas to the
Company's Greenleaf Power Plants.
TEXAS CITY AND CLEAR LAKE TRANSACTIONS
In June 1997, the Company acquired a 50% equity interest in the Texas City
Power Plant and the Clear Lake Power Plant for a total purchase price of $35.4
million, subject to final adjustments. The Company acquired its 50% interest in
these plants through the acquisition of 50% of the capital stock of Enron
Dominion Cogen Corp. ("EDCC") from Enron Power Corp. EDCC was subsequently
renamed Texas Cogeneration Company ("TCC"). The remaining 50% shareholder
interest in TCC is owned by Dominion Cogen, Inc. In addition to the purchase of
the stock of TCC, the Company purchased from existing lenders the $155.6 million
of outstanding non-recourse project financing of the Texas City Power Plant
(approximately $53.0 million) and the Clear Lake Power Plant (approximately
$102.6 million) (see Note 6, "Texas City and Clear Lake Power Plants").
The Company accounts for its investment in TCC under the equity method. The
Texas City and Clear Lake Power Plants are operated by the Company under a
one-year contract with automatic renewal provisions.
Texas City Power Plant -- The Texas City Power Plant is a 450 megawatt
gas-fired cogeneration facility located in Texas City, Texas. The plant
commenced commercial operation in June 1987.
Electricity generated by the Texas City Power Plant is sold under two
separate long-term agreements to: (i) Texas Utilities Electric Company ("TUEC")
under an original 12-year power sales agreement terminating in June 1999, which
has been extended to September, 2002, and (ii) Union Carbide Company ("UCC")
under an original 12-year power sales agreement terminating in June 1999. Each
power sales agreement contains provisions for capacity and energy payments. The
TUEC power sales agreement provides for a firm capacity payment for 410
megawatts. The UCC power sales agreement provides for a firm capacity payment
for 20 megawatts.
Clear Lake Power Plant -- The Clear Lake Power Plant is a 377 megawatt
gas/hydrogen-fired cogeneration facility located in Pasadena, Texas. The plant
commenced commercial operation in December 1984.
Electricity generated by the Clear Lake Power Plant is sold under three
separate long-term agreements to: (i) Texas New Mexico Power Company ("TNP")
under an original 20-year power sales agreement terminating in 2004, (ii)
Houston Light & Power Company under an original 10-year power sales agreement
terminating in 2005, and (iii) Hoescht Celanese Chemical Group under an original
10-year power sales agreement terminating in 2004. Each power sales agreement
contains provisions for capacity and energy payments.
DIGHTON AND TIVERTON TRANSACTIONS
In October 1997, the Company executed agreements with Energy Management,
Inc. ("EMI") to invest in the development of two merchant power plants slated
for start-up in 1999 and early 2000. The Company
F-24
<PAGE> 79
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
invested $16.0 million in a 169 megawatt gas-fired combined-cycle plant to be
built in Dighton, Massachusetts. The Company will receive a preferred payment
stream at a rate of approximately 12% on its investment.
The Company accounts for its investment in Dighton under the equity method
of accounting. During construction of the facility, the Company capitalizes
interest on the investment at a rate equal to the average corporate cost of
debt.
Under the terms of the above agreements, the Company has also been granted
an exclusive option to purchase an ownership interest in, and to partner with,
EMI on a 265 megawatt gas-fired plant under development in Tiverton, Rhode
Island. EMI and the Company would be co-general partners for the project. The
Company intends to invest up to $43.0 million of equity in the development of
the Tiverton Power Plant.
AUBURNDALE AND GORDONSVILLE TRANSACTIONS
In October 1997, the Company acquired a 50% interest in both the Auburndale
Power Plant and the Gordonsville Power Plant for a total purchase price of $42.4
million, subject to final adjustments. The Company acquired its interest in
these plants from Norweb Power Services Limited and Northern Hydro Limited, both
wholly-owned subsidiaries of Norweb PLC. The Company accounts for its investment
in the Auburndale Power Plant and Gordonsville Power Plant under the equity
method.
Auburndale Power Plant -- The Auburndale Power Plant is a 150 megawatt
gas-fired cogeneration facility located outside of Orlando, Florida. The
Auburndale Power Plant commenced commercial operation in July 1994 and sells
capacity and energy to Florida Power Corporation under three 20-year power sales
agreements terminating in December 2013.
Gordonsville Power Plant -- The Gordonsville Power Plant is a 240 megawatt
gas-fired cogeneration facility located near Gordonsville, Virginia. The
Gordonsville Power Plant commenced commercial operations in June 1994 and sells
capacity and energy to Virginia Electric and Power Company under two 30-year
power sales agreements terminating in 2024.
The Gordonsville and Auburndale Power Plants are operated by Edison Mission
Operations & Maintenance, Inc. ("EMOM"), an affiliate of Edison Mission Energy.
The operating agreements between EMOM and the two facilities expire in December
2013. EMOM is paid on a cost-plus basis for all direct labor plus reimbursement
of certain costs, an operating fee and an incentive based upon performance.
GAS ENERGY INC. AND GAS ENERGY COGENERATION INC. TRANSACTION
In December 1997, the Company acquired 100% of the capital stock of Gas
Energy Inc. ("GEI") and Gas Energy Cogeneration Inc. ("GECI") from The Brooklyn
Union Gas Company ("BUG"), for a total purchase price of $100.9 million, subject
to final adjustments. GEI and GECI were both wholly-owned subsidiaries of BUG
and have (i) a 50% interest in the Kennedy International Airport Power Plant,
(ii) a 50% interest in the Stony Brook Power Plant, (iii) a 45% interest in the
Bethpage Power Plant, (iv) an 11.36% interest in the Lockport Power Plant and
(v) a 100% interest in three fuel management contracts. The Company accounts for
its investments in the above power plants under the equity method.
The Kennedy International Airport Cogeneration Power Plant is a 107
megawatt gas-fired cogeneration facility located in Queens, New York. Steam and
electricity generated by the Kennedy International Airport Cogeneration Power
Plant are sold to the Port Authority of New York and New Jersey to service the
John F. Kennedy International Airport under a 20-year power sales agreement
terminating in 2015.
The Stony Brook Power Plant is a 40 megawatt gas-fired cogeneration
facility located at the State University of New York in Stony Brook, New York.
Steam and electricity generated by the Stony Brook
F-25
<PAGE> 80
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Power Plant are sold to the State University of New York at Stony Brook under a
20-year power sales agreement terminating in 2015, and excess electricity is
sold to Long Island Lighting Company ("LILCo").
The Bethpage Power Plant is a 57 megawatt gas-fired cogeneration facility
located in Bethpage, New York. Steam and electricity generated by the Bethpage
Power Plant are sold to the Northrop Grumman Corporation under a 15-year power
sales agreement expiring in 2004, and excess electricity is sold to LILCo. On
February 5, 1998, the Company purchased the remaining 55% interest in the
Bethpage Power Plant for approximately $4.6 million.
The Lockport Power Plant is a 184 megawatt gas-fired cogeneration facility
located in Lockport, New York. Steam and electricity generated by the Lockport
Power Plant are sold to a General Motors plant under a 15-year power sales
agreement terminating in 2007, and excess electricity is sold to New York State
Electric and Gas ("NYSEG").
4. ACCOUNTS RECEIVABLE
At December 31, 1997, accounts receivable totaled $42.8 million, which
included $7.7 million receivable from related parties. Accounts receivable from
related parties at December 31, 1997 and 1996 include the following (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
----------------
1997 1996
------ ------
<S> <C> <C>
Nisseqougue Cogen Partners................................. $4,140 $ --
TBG Cogen Partners......................................... 1,490 --
Texas Cogeneration Company................................. 903 --
Sumas Cogeneration Company, L.P............................ 527 590
Geothermal Energy Partners, Ltd............................ 275 350
O.L.S. Energy-Agnews, Inc.................................. 269 687
KIAC Partners.............................................. 68 --
Electrowatt Ltd. and subsidiaries.......................... -- 1,199
------ ------
Accounts receivable from related parties............ $7,672 $2,826
====== ======
</TABLE>
At December 31, 1996, the $1.2 million receivable from Electrowatt Ltd.
(the previous indirect sole owner of the Company) was for reimbursement of costs
for the sale of Electrowatt Ltd.'s ownership of the Company's common stock
during the Company's initial public offering in September 1996.
5. RESULTS OF UNCONSOLIDATED INVESTMENTS
The Company has unconsolidated investments in power projects which are
accounted for under the equity method. Investments in less-than-majority-owned
affiliates and the nature and extent of these
F-26
<PAGE> 81
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
investments change over time. The combined results of operations and financial
position of the Company's equity-basis affiliates are summarized below (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Condensed Statement of Operations:
Operating revenue.................... $ 271,494 $ 77,417 $ 63,981
Net income (loss).................... 30,264 14,021 (1,043)
Condensed Balance Sheet:
Assets............................... 1,693,454 235,682 239,149
Liabilities.......................... 1,276,922 200,667 213,850
Investments (see Note 2)............. 237,241 13,061 7,306
Project development costs............ 1,919 875 912
---------- ---------- ----------
Total investments............ 239,160 13,936 8,218
========== ========== ==========
Company's share of net income (loss)... $ 15,819 $ 6,537 $ (2,854)
</TABLE>
The following details the Company's income from investments in
unconsolidated power projects and the service contract revenue recorded by the
Company related to those power projects (in thousands):
<TABLE>
<CAPTION>
INCOME FROM UNCONSOLIDATED
INVESTMENTS IN POWER PROJECTS SERVICE CONTRACT REVENUE
----------------------------- ------------------------
FOR THE YEARS ENDED DECEMBER 31,
COMPANY'S --------------------------------------------------------
OWNERSHIP 1997 1996 1995 1997 1996 1995
PERCENTAGE -------- ------- -------- ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Sumas Cogeneration Company, L.P.... (1) $ 8,565 $6,396 $(3,049) $2,073 $2,034 $2,021
O.L.S. Energy-Agnews, Inc.......... 20% 17 (190) (82) 1,712 1,954 1,515
Geothermal Energy Partners, Ltd.... 5% 454 331 277 3,024 3,990 3,547
Texas Cogeneration Company......... 50% 6,331 -- -- 2,782 -- --
Auburndale Power Partners, L.P..... 50% (245) -- -- -- -- --
Gordonsville Energy, L.P........... 50% 404 -- -- -- -- --
KIAC Partners...................... 50% (190) -- -- -- -- --
Nissequogue Cogen Partners......... 50% 60 -- -- -- -- --
TBG Cogen Partners................. 45% 223 -- -- -- -- --
Lockport Energy Associates, L.P.... 11% 200 -- -- -- -- --
------- ------ ------- ------ ------ ------
$15,819 $6,537 $(2,854) $9,591 $7,978 $7,083
======= ====== ======= ====== ====== ======
</TABLE>
The Company received $20.3 million and $1.3 million in distributions from
Sumas for the years ended December 31, 1997 and 1996, respectively. The Company
received $767,000 in distributions from Lockport Energy Associates, L.P. for the
year ended December 31, 1997.
- ---------------
(1) On September 30, 1997, the partnership agreement governing Sumas
Cogeneration Company, L.P. ("Sumas") was amended changing the distribution
percentages to the partners. As provided for in the amendment, the Company's
percentage share of the project's cash flow increased from 50% to
approximately 70% through June 30, 2001, based on certain specified
payments. Thereafter, the Company will receive 50% of the project's cash
flow until a 24.5% pre-tax rate of return on its original investment is
achieved, at which time the Company's equity interest in the partnership
will be reduced to 0.1%. As a result of the amendment of the partnership
agreement and the receipt of certain distributions during 1997, the
Company's investment in Sumas was reduced to zero. Because the investment
has been reduced to zero and there are no continuing obligations of the
Company related to Sumas, the Company expects that income recorded in future
periods will approximate the amount of cash received from partnership
distributions.
F-27
<PAGE> 82
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
6. NOTES AND LOANS RECEIVABLE
SUMAS POWER PLANT
In May 1993, in accordance with the Sumas partnership agreement, the
Company was entitled to receive a distribution of $1.5 million and Sumas Energy,
Inc. ("SEI"), the Company's partner in Sumas, was required to make a capital
contribution of $1.5 million. In order to meet SEI's $1.5 million capital
contribution requirement, the Company loaned $1.5 million to the sole
shareholder of SEI, who in turn loaned the funds to SEI, who in turn contributed
the capital to Sumas. The interest rate on the loan was 20% and was secured by a
security interest in the loan between SEI and its sole shareholder. The Company
received all principal plus accrued interest totaling $2.8 million in 1997.
In March 1994, the Company loaned $10.0 million to the sole shareholder of
SEI. The interest rate on the loan was 16.25%. The loan was secured by a pledge
to Calpine of SEI's interest in Sumas. The Company deferred the recognition of
interest income from these notes until Sumas generated net income.
During 1997, the $10.0 million loan was sold to a third party. The Company
received all unpaid principal and interest related to both loans and recognized
a total of $6.9 million of the interest income during 1997 (of which $3.5
million was previously deferred). In addition, the Company recorded a $1.1
million gain upon the sale of the $10.0 million loan, which was recorded in
Other (income) expense. In 1996, the Company recognized $2.1 million of interest
income related to the above two loans, which represents the portion of Sumas'
earnings not recognized by the Company related to its equity investment in
Sumas.
In September 1997, the Company entered into a loan agreement with SEI's
sole shareholder wherein the Company agreed to make available a line of credit
up to $15.0 million, the proceeds of which are required to be used to develop a
new project. SEI has guaranteed the payment and performance of obligations under
this agreement and borrowings under the agreement will be collateralized by the
new project and the sole shareholder's 100% interest in SEI. The loan agreement
will expire on December 31, 2003.
TEXAS CITY AND CLEAR LAKE POWER PLANTS
In connection with the acquisition of a 50% interest in TCC, the Company
purchased from the existing lenders the $155.6 million of outstanding project
debt of the Texas City Power Plant (approximately $53.0 million) and the Clear
Lake Power Plant (approximately $102.6 million). At December 31, 1997, there
were loans receivable of $37.1 million from Texas City and $94.7 million from
Clear Lake (of these amounts $30.5 million is current and $101.3 million is long
term). The effective interest rate on the loan to the Texas City Power Plant
including the effect of the swap arrangement, was approximately 7.9% at December
31, 1997; the loan matures June 30, 1999. The effective interest rate on the
loan to the Clear Lake Power Plant, including the effect of the existing swap
arrangement, was approximately 8.3%; the loan matures December 31, 2003. Both
notes are secured by the assets of the respective partnerships.
CALPINE VAPOR INC.
In November 1995, Calpine Vapor Inc. ("Vapor") entered into agreements with
Constructora y Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain
Mexican bank lenders to loan $18.5 million to Coperlasa in connection with a
geothermal steam production contract at the Cerro Prieto geothermal resource
("Cerro Prieto Project") in Baja California, Mexico (see Note 2, Concentration
of Credit Risks). The resource currently produces electricity from geothermal
power plants owned and operated by Comision Federal de Electricidad ("CFE"),
Mexico's national utility. The steam field contract is between Coperlasa and
CFE. Vapor receives fees for technical services provided to the project. At
December 31, 1997 and 1996, notes receivable were $16.1 million and $18.0
million, respectively. Interest accrues on the outstanding notes receivable at
approximately 18.9%. The Company is deferring the recognition of interest income
from this note
F-28
<PAGE> 83
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
until the Cerro Prieto Project generates sufficient cash flows available for
distribution to support the collectibility of accrued interest.
7. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
At December 31, 1997 and 1996, the Company had a $50.0 million credit
facility available with a consortium of commercial lending institutions which
include The Bank of Nova Scotia, ING, Sumitomo Bank of California and Canadian
Imperial Bank of Commerce. As of December 31, 1997, the Company had no
borrowings and $9.4 million of letters of credit outstanding. This amount
reflects $6.0 million to secure performance with the Clear Lake Power Plant,
$1.5 million to secure performance under a power sales agreement, and $1.9
million related to operating expenses at the Watsonville Power Plant. At
December 31, 1996, the Company had no borrowings and $5.9 million of letters of
credit outstanding, which reflected $3.0 million to secure performance with the
Pasadena Power Plant and $2.9 million related to operating expenses at the
Watsonville Power Plant. Borrowings bear interest at The Bank of Nova Scotia's
base rate or at the London InterBank Offering Rate ("LIBOR"), plus an applicable
margin. Interest is paid on the last day of each interest period for such loans,
but not less often than quarterly, based on the principal amount outstanding
during the period for base rate loans, and on the last day of each applicable
interest period, but not less often than 90 days, for LIBOR loans. The credit
agreement expires in September 1999. The credit agreement specified that the
Company maintain certain covenants with which the Company was in compliance.
Commitment fees related to this line of credit are charged based on 0.50% of
committed unused credit.
At December 31, 1997 and 1996, the Company had a loan facility with
available borrowings totaling $1.2 million. As of December 31, 1997, the Company
had no borrowings and $74,000 of letters of credit outstanding. There were no
borrowings and $900,000 of letters of credit outstanding as of December 31,
1996.
8. NON-RECOURSE PROJECT FINANCING
The components of non-recourse project financing as of December 31, 1997
and 1996 are (in thousands):
<TABLE>
<CAPTION>
1997 1996
-------- --------
<S> <C> <C>
Senior-term loans:
Fixed rate portion........................... $ -- $ 73,000
Variable rate portion........................ -- 20,000
Premium on debt.............................. -- 1,824
-------- --------
Total senior-term loans.............. -- 94,824
Junior-term loan............................... -- 19,965
Notes payable to banks......................... 295,859 194,478
-------- --------
Total long-term debt................. 295,859 309,267
Less current portion................. 112,966 30,627
-------- --------
Long-term debt, less current
portion............................ $182,893 $278,640
======== ========
</TABLE>
Senior-Term and Junior-Term Loans -- The Company entered into Senior-Term
and Junior-Term Loans in connection with the Company's acquisition of CGC in
1993. On July 8, 1997, the Company repaid all Senior-Term and Junior-Term Loans
before their maturity date from the proceeds of the 8 3/4% Senior Notes Due
2007. In connection with this transaction, the Company terminated one swap
transaction and retained one swap transaction, which was redesignated to other
floating rate financings. The Company had entered into swap transactions to
minimize the impact of changes in interest rates on a portion of the Senior-
Term loans. At December 31, 1997, the remaining swap had an effective interest
rate of 9.9%. The Company
F-29
<PAGE> 84
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
is potentially exposed to credit risk in an event of non-performance by the
other parties to the swap agreements.
Notes Payable to Banks -- In June 1995, the Company entered into an
agreement with Sumitomo Bank to finance the acquisition of the Greenleaf Power
Plants. Of the $71.9 million debt outstanding at December 31, 1997, $56.8
million bears interest fixed at 7.4%, with the remaining floating rate portion
accruing interest at LIBOR, plus an applicable margin (6.5% at December 31,
1997). At December 31, 1996, $74.7 million of debt was outstanding, of which
$59.0 million was at the fixed interest rate of 7.4%, with the remaining
floating rate portion accruing interest at approximately 6.2%. This debt is
secured by all of the assets of the Greenleaf Power Plants. Interest on the
floating rate portion may be at Sumitomo's base rate plus an applicable margin
or at LIBOR plus an applicable margin. Interest on base rate loans is paid at
the end of each calendar quarter, and interest on LIBOR based loans is paid on
each maturity date, but not less often than quarterly, based on the principal
amount outstanding during the period. At the Company's discretion, the LIBOR
based loans may be held for various maturity periods of at least 1 month up to
12 months. The $71.9 million debt is being repaid quarterly, with a final
maturity date of December 31, 2010. The credit agreement specifies that the
Company maintain certain covenants in which the Company was in compliance at
December 31, 1997.
On August 29, 1996, the Company entered into an agreement with Banque
Nationale de Paris ("BNP") to finance the acquisition of the Gilroy Power Plant.
As of December 31, 1997, BNP had provided a $120.5 million loan consisting of a
15-year tranche in the amount of $86.9 million and an 18-year tranche in the
amount of $33.6 million. As of December 31, 1996, BNP had provided a $119.8
million loan consisting of a 15-year tranche in the amount of $84.8 million and
an 18-year tranche in the amount of $35.0 million. The debt is secured by all of
the assets of the Gilroy Power Plant. A portion of the BNP notes bears interest
fixed at a weighted average of 6.6% as of December 31, 1997 and 1996 (see
discussion below), with the remainder accruing interest at floating rate.
Interest on the floating rate portion may be at BNP's base rate plus an
applicable margin or at LIBOR plus an applicable margin (7.1% and 6.6% at
December 31, 1997 and 1996, respectively). Interest on the loans is payable not
less often than quarterly. Interest on LIBOR based loans is paid on each
maturity date, but not less often than quarterly. At the Company's discretion,
LIBOR based loans may be held for various maturity periods of at least 1 month
and up to 12 months. The $120.5 million debt is repaid semi-annually with a
final maturity date of August 28, 2011. Commitment fees are charged based on 1%
to 1.125% of committed unused credit. The Company entered into four interest
rate swap agreements to minimize the impact of changes in interest rates. These
agreements fix the interest on $85.1 million of principal at a weighted average
interest rate of 6.6%. The interest rate swap agreements mature through August
2011. The Company is exposed to credit risk in the event of non-performance by
the other parties to the swap agreements.
On June 23, 1997, the Company entered into a $125.0 million non-recourse
project financing with The Bank of Nova Scotia. Proceeds were utilized for the
acquisition of the 50% interest in TCC and the purchase from the lenders of
$155.6 million of outstanding non-recourse project financing. The $125.0 million
non-recourse project financing matures on June 22, 1998. The Company expects to
refinance this non-recourse project financing prior to maturity. On December 31,
1997, $103.4 million of borrowings were outstanding which bear interest at The
Bank of Nova Scotia's base rate or LIBOR, plus an applicable margin
(approximately 7.2% at December 31, 1997). The Company utilized swap
arrangements to minimize the impact of potential changes in interest rates on
the project debt. The effective interest rate, including the effect of the swap
arrangement, was approximately 7.1% at December 31, 1997. The interest rate swap
agreements mature in June 1998. The Company has potential exposure to credit
risk in the event of non-performance by other parties to the swap agreements.
The credit agreement specifies that the Company maintain certain covenants in
which the Company was in compliance at December 31, 1997.
F-30
<PAGE> 85
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
At December 31, 1997, the Company held a credit agreement with ING to
provide $151.8 million of non-recourse project financing for the Pasadena Power
Plant (see Note 3, "Pasadena Cogeneration Project"). Interest is payable at
ING's base rate or the Federal Funds Rate plus an applicable margin on the last
day of each calendar quarter, or at LIBOR plus an applicable margin upon
maturity of the loan, but not less often than quarterly. All interest is due and
payable upon conversion of the construction loan to a term loan. Subject to the
terms of the credit agreement, all or part of the construction loan will be
converted to a term loan upon completion of construction. Commitment fees are
charged based on 0.375% of committed unused credit. No borrowings were
outstanding at December 31, 1997 and 1996. In January 1998, the Company borrowed
$35.9 million in accordance with the terms of the credit agreement. Beginning in
June 1997, the Company was obligated to enter into several hedge transactions
pursuant to the credit agreement, the notional values of which range from $25.0
million to $75.0 million, all of which were hedged at 7.2%.
The annual principal maturities of the non-recourse project financing
outstanding at December 31, 1997 are as follows (in thousands):
<TABLE>
<S> <C>
1998.............................. $112,966
1999.............................. 8,683
2000.............................. 10,352
2001.............................. 10,631
2002.............................. 11,132
Thereafter........................ 142,095
--------
Total................... $295,859
========
</TABLE>
The non-recourse project financing is held by subsidiaries of Calpine. The
debt agreements governing the non-recourse project financing generally restrict
their ability to pay dividends, make distributions or otherwise transfer funds.
The dividend restrictions in such agreements generally require that, prior to
the payment of dividends, distributions or other transfers, the subsidiary or
other affiliate must provide for the payment of other obligations, including
operating expenses, debt service and reserves.
9. NOTES PAYABLE
At December 31, 1996, the Company had a non-interest bearing promissory
note for $6.5 million payable to Natomas Energy Company, a wholly-owned
subsidiary of Maxus Energy Company. This note had been discounted to yield 8.0%
per annum, due September 9, 1997, and had a carrying value of $6.2 million at
December 31, 1996. On July 8, 1997, the Company repaid the promissory note
before its maturity date from the proceeds of the 8 3/4% Senior Notes Due 2007
(see Note 10).
10. SENIOR NOTES
On July 8, 1997, the Company issued $200.0 million aggregate principal
amount of 8 3/4% Senior Notes Due 2007. Transaction costs of $9.7 million
incurred in connection with the debt offering were capitalized and are included
in Other assets and amortized over the ten-year life of the 8 3/4% Senior Notes
Due 2007.
On September 10, 1997, the Company issued an additional $75.0 million
aggregate principal amount of 8 3/4% Senior Notes Due 2007.
In May and June 1997, the Company executed five interest rate hedging
transactions related to debt. The notional value of the debt was $182.0 million
and was designed to eliminate interest rate risk for the period from May 1997 to
July 1997 when the $200.0 million of 8 3/4% Senior Notes Due 2007 were priced.
These interest rate hedging transactions were designated as a hedge of the
anticipated bond offering, and the resulting $3.0 million cost resulting from
the hedges is being amortized over the life of the bonds. The effective
F-31
<PAGE> 86
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
interest rate on the $275.0 million aggregate principal amount after the hedging
transactions and the amortization of transaction costs was 9.1%.
The 8 3/4% Senior Notes Due 2007 will mature on July 15, 2007. The Company
has no sinking fund or mandatory redemption obligations with respect to the
8 3/4% Senior Notes Due 2007. Interest is payable semi-annually on January 15
and July 15 of each year while the 8 3/4% Senior Notes Due 2007 are outstanding,
commencing on January 15, 1998. Based on the traded yield to maturity, the
approximate fair market value of the 8 3/4% Senior Notes Due 2007 was $280.5
million as of December 31, 1997.
On May 16, 1996, the Company issued $180.0 million aggregate principal
amount of 10 1/2% Senior Notes Due 2006. Transaction costs of $5.1 million
incurred in connection with the public debt offering were recorded in Other
assets and amortized over the ten-year life of the 10 1/2% Senior Notes Due
2006. The effective interest rate of the $180.0 million aggregate principal
amount after the amortization of transaction costs was 10.7%.
The 10 1/2% Senior Notes Due 2006 will mature on May 15, 2006. The Company
has no sinking fund or mandatory redemption obligations with respect to the
10 1/2% Senior Notes Due 2006. Interest is payable semi-annually on May 15 and
November 15. Based on the traded yield to maturity, the approximate fair market
value of the 10 1/2% Senior Notes Due 2006 was $196.2 million as of December 31,
1997.
The 9 1/4% Senior Notes Due 2004 will mature on February 1, 2004. The
Company has no sinking fund or mandatory redemption obligations with respect to
the 9 1/4% Senior Notes Due 2004. Interest is payable semi-annually on February
1 and August 1. Based on the traded yield to maturity, the approximate fair
market value of the 9 1/4% Senior Notes Due 2004 was $108.7 million as of
December 31, 1997. The effective interest rate on the $105.0 million aggregate
principal amount after amortization of transaction costs was 9.6%.
The Senior Note indentures specify that the Company maintains certain
covenants with which the Company was in compliance. The Company may, under
certain circumstances, be limited in its ability to make restricted payments, as
defined, which include dividends and certain purchases and investments, incur
additional indebtedness and engage in certain transactions.
11. PROVISION FOR INCOME TAXES
The Company follows the liability method of accounting for income taxes
whereby deferred income taxes are recognized for the tax consequences of
"temporary differences" to the extent they are not reduced by net operating loss
and tax credit carryforwards by applying enacted statutory rates.
The components of the deferred tax liability as of December 31, 1997 and
1996 are (in thousands):
<TABLE>
<CAPTION>
1997 1996
--------- ---------
<S> <C> <C>
Expenses deductible in a future period............... $ 4,122 $ 3,329
Net operating loss and credit carryforwards.......... 20,260 19,856
Other differences.................................... 2,524 494
--------- ---------
Deferred tax asset................................. 26,906 23,679
--------- ---------
Property differences................................. (156,526) (119,842)
Difference in taxable income and income from
investments recorded on the equity method.......... (5,798) (2,753)
Other differences.................................... (6,632) (1,469)
--------- ---------
Deferred tax liabilities........................... (168,956) (124,064)
--------- ---------
Net deferred tax liability...................... $(142,050) $(100,385)
========= =========
</TABLE>
F-32
<PAGE> 87
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
The net operating loss and credit carryforwards consist of federal net
operating loss carryforwards which expire 2005 through 2010 and federal and
state alternative minimum tax credit carryforwards which can be carried forward
indefinitely. At December 31, 1997, the federal net operating loss carryforwards
were approximately $11.3 million. At December 31, 1997, state net operating
losses have been fully utilized. At December 31, 1997, federal and state
alternative minimum tax credit carryforwards were approximately $10.6 million
and $3.6 million, respectively. In 1997 and 1996, the Company decreased its
deferred income tax liability by $2.1 million and $769,000 to reflect the change
in the California state income tax rate from 9.3% to 8.8% effective January 1,
1997 and to reflect the decrease in the California tax rate due to the Company's
expansion into states other than California.
Realization of the deferred tax assets and federal net operating loss
carryforwards is dependent, in part, on generating sufficient taxable income
prior to expiration of the loss carryforwards. In September 1996, the Company
underwent an ownership change as a result of the initial public offering of the
Company's common stock. This ownership change limits the amount of net operating
loss and credit carryforwards available to offset current tax liabilities.
Although realization is not assured, management believes it is more likely than
not that all of the deferred tax asset will be realized based on estimates of
future taxable income. The amount of the deferred tax asset considered
realizable, however, could be reduced in the near term if estimates of future
taxable income during the carryforward period are reduced.
The provision for income taxes for the years ended December 31, 1997, 1996
and 1995 consists of the following (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Current:
Federal..................................... $ 1,892 $ 5,671 $ 3,085
State....................................... 917 1,805 1,163
Deferred:
Federal..................................... 14,989 3,890 816
State....................................... 2,897 (801) (15)
Adjustment in state tax rate (net of
federal benefit)....................... (2,113) (769) --
Revision in prior years' tax estimates... (122) (732) --
------- ------- -------
Total provision..................... $18,460 $ 9,064 $ 5,049
======= ======= =======
</TABLE>
The Company's effective rate for income taxes for the years ended December
31, 1997, 1996 and 1995 differs from the United States statutory rate, as
reflected in the following reconciliation.
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
United States statutory tax rate....................... 35.0% 35.0% 35.0%
State income tax, net of federal benefit............... 5.0 6.0 6.0
Depletion allowance.................................... (2.1) (2.3) (0.3)
Effect of change in state tax rates, net of federal
benefit.............................................. -- (3.0) --
Decrease in California deferred tax due to Company's
expansion into other states, net of federal
benefit.............................................. (4.1) -- --
Revision in prior years' tax estimates................. -- (2.6) --
Other, net............................................. 0.9 (0.4) (0.1)
---- ---- ----
Effective income tax rate.................... 34.7% 32.7% 40.6%
==== ==== ====
</TABLE>
F-33
<PAGE> 88
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
12. RETIREMENT SAVINGS PLAN
The Company has a defined contribution savings plan under Section 401(a)
and 501(a) of the Internal Revenue Code. The plan provides for tax deferred
salary deductions and after-tax employee contributions. Employees automatically
become participants on the first quarterly entry date after completion of three
months of service. Contributions include employee salary deferral contributions
and a 3% employer profit-sharing contribution. Employer profit-sharing
contributions in 1997, 1996, and 1995 totaled $588,000, $485,000 and $350,000,
respectively.
13. STOCKHOLDERS' EQUITY
Common Stock
In September 1996, the Company completed an initial public offering of
18,045,000 shares of its common stock with $0.001 par value per share (the
"Common Stock Offering"). In the Common Stock Offering, the Company issued and
sold 5,477,820 shares of common stock and Electrowatt Ltd. ("Electrowatt") sold
12,567,180 shares of common stock, representing its entire ownership interest in
the Company. As a result of the Common Stock Offering, Electrowatt no longer
owns any interest in the Company. The Company received approximately $82.1
million of net proceeds from the Common Stock Offering. In October 1996, the
Company issued an additional 1,793,400 shares of common stock to cover
over-allotments of shares in connection with the Common Stock Offering and
received approximately $27.1 million of net proceeds. In connection with the
Common Stock Offering, the Company completed a 5.194-for-1 stock split of the
Company's common stock and converted the Company's outstanding Series A
Preferred Stock into shares of common stock. The accompanying financial
statements reflect the stock split retroactively for all periods presented.
Preferred Stock and Preferred Share Purchase Rights
The Company had 5,000,000 authorized shares of Series A Preferred Stock,
all of which were issued on March 21, 1996 to Electrowatt. The shares of Series
A Preferred Stock were not publicly traded. No dividends were payable on the
Series A Preferred Stock. The Series A Preferred Stock contained provisions
regarding liquidation and conversion rights. Upon the consummation of the Common
Stock Offering, all of the Series A Preferred Stock was converted into
approximately 2.2 million shares of common stock and sold to the public in the
Common Stock Offering by Electrowatt.
On June 5, 1997, the Board of Directors adopted a Stockholders Rights Plan
("Rights Plan") to strengthen the Board of Directors ability to protect the
Company's stockholders. The Rights Plan is designed to protect against abusive
or coercive takeover tactics that are not in the best interests of the Company
and its stockholders. To implement the Rights Plan, the Board of Directors
declared a dividend of one preferred share purchase right (a "Right") for each
outstanding share of common stock, par value $0.001 per share, held on record as
of June 18, 1997. On December 31, 1997, there were 19,905,233 Rights
outstanding. Each Right initially represents a contingent right to purchase,
under certain circumstances, one one-thousandth of a share (a "Unit") of Series
A Junior Participating Preferred Stock, par value $0.001 per share (the
"Preferred Stock"), of the Company at a price of $80.00 per Unit, subject to
adjustment. The Rights become exercisable and trade independently from the
Company's common stock upon the public announcement of the acquisition by a
person or group of 15% or more of the Company's common stock, or ten days after
commencement of a tender or exchange offer that would result in the acquisition
of 15% or more of the Company's common stock. Each Unit of Preferred Stock
purchased upon exercise of the Rights will be entitled to a dividend equal to
any dividend declared per share of common stock and will have one vote, voting
together with the common stock. In the event of liquidation, each share of
Preferred Stock will be entitled to any payment made per share of common stock.
F-34
<PAGE> 89
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
If the Company is acquired in a merger or other business combination
transaction after a person or group has acquired 15% or more of the Company's
common stock, each Right will entitle its holder to purchase at the Right's
exercise price a number of the acquiring company's common shares having a market
value of twice such exercise price. In addition, if a person or group acquires
15% or more of the Company's common stock, each Right will entitle its holder
(other than the acquiring person or group) to purchase, at the Right's exercise
price, a number of fractional shares of the Company's Preferred Stock or shares
of common stock having a market value of twice such exercise price.
The Rights expire June 18, 2007 unless redeemed earlier by the Company's
Board of Directors. The Board of Directors can redeem the Rights at a price of
$0.01 per Right at any time before the Rights become exercisable, and thereafter
only in limited circumstances.
14. STOCK-BASED COMPENSATION PROGRAMS
1996 Employee Stock Purchase Plan
The Company adopted the 1996 Employee Stock Purchase Plan ("ESPP") in July
1996. Eligible employees may purchase up to 275,000 shares of common stock at
semi-annual intervals through periodic payroll deductions. Purchases are limited
to 15 percent of an employee's eligible compensation, up to a maximum of $25,000
per year. Shares are purchased on January 31 and July 31 of each year. Under the
ESPP, 54,149 shares were issued at a weighted average fair value of $13.65 per
share in 1997. On January 30, 1998, employees participating in the ESPP
purchased an additional 30,385 shares at a weighted average fair value of $13.39
per share. The purchase price is 85% of the lower of (i) the fair market value
of the common stock on the participant's entry date into the offering period, or
(ii) the fair market value on the semi-annual purchase date.
1996 Stock Incentive Plan
The Company adopted the 1996 Stock Incentive Plan ("SIP") in September
1996. The SIP succeeded the Company's previously adopted stock option program.
The Company accounts for the SIP under Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" under which no compensation cost
has been recognized. Had compensation cost for the SIP been determined
consistent with the methodology of SFAS No. 123, "Accounting for Stock-Based
Compensation", the Company's net income and earnings per share would have been
reduced to the following pro forma amounts (in thousands, except per share
amounts):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C> <C>
Net income As reported $34,699 $18,692 $ 7,378
Pro Forma $33,528 $18,145 $ 7,232
Basic earnings per share As reported $ 1.74 $ 1.45 $ 0.71
Pro Forma $ 1.68 $ 1.41 $ 0.70
Diluted earnings per share As reported $ 1.65 $ 1.26 $ 0.67
Pro Forma $ 1.60 $ 1.22 $ 0.66
</TABLE>
The fair value of options granted in 1995, 1996 and 1997 was $1.23, $3.29
and $10.28 on the date of grant using the Black-Scholes option pricing model
with the following weighted-average assumptions: expected dividend yields of 0%,
expected volatility of 44%, 27% and 0% for 1997, 1996 and 1995, risk-free
interest rates of 5.8%, 6.2% and 5.4% for 1997, 1996 and 1995, respectively, and
expected lives of 3 years for 1995 and 1996, and 7 years for 1997.
Because the SFAS No. 123 methodology of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in
F-35
<PAGE> 90
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
future years. The Company may grant options for up to 4,041,858 shares under the
SIP. As of December 31, 1997, the Company had granted options to purchase
2,519,803 shares of common stock. Under the SIP, the option exercise price
equals the stock's fair market value on date of grant. The SIP options generally
vest after four years and expire after 10 years. Changes in options outstanding,
granted, exercisable and cancelled by the Company during the years 1997, 1996,
and 1995, whether under the option or purchase plan were as follows:
<TABLE>
<CAPTION>
AVAILABLE FOR WEIGHTED
OPTION OR NUMBER OF AVERAGE
AWARD SHARES EXERCISE PRICE
------------- --------- --------------
<S> <C> <C> <C>
Beginning Balance January 1, 1995................ 1,160,782 1,436,141 $ 1.53
Granted..................................... (444,333) 444,333 4.91
Cancelled................................... 25,963 (25,963) 2.13
--------- --------- ---------
Outstanding December 31, 1995.................... 742,412 1,854,511 2.34
Additional shares reserved..................... 1,444,935 -- --
Granted..................................... (547,579) 547,579 8.71
Exercised................................... -- (5,000) 1.85
Cancelled................................... 56,796 (56,796) 7.90
--------- --------- ---------
Outstanding December 31, 1996.................... 1,696,564 2,340,294 3.69
Granted..................................... (394,217) 394,217 18.31
Exercised................................... -- (163,156) 1.33
Cancelled................................... 51,552 (51,552) 8.55
--------- --------- ---------
Outstanding December 31, 1997.................... 1,353,899 2,519,803 $ 6.03
========= ========= =========
Options exercisable:
December 31, 1995................................ 1,217,340 $ 1.15
December 31, 1996................................ 1,445,746 1.71
December 31, 1997................................ 1,635,469 3.23
</TABLE>
The following tables summarizes information concerning outstanding and
exercisable options at December 31, 1997:
<TABLE>
<CAPTION>
OUTSTANDING OPTIONS
---------------------------------------------------- OPTIONS EXERCISABLE
WEIGHTED AVERAGE --------------------------------
REMAINING WEIGHTED WEIGHTED
RANGE OF NUMBER OF CONTRACTUAL LIFE AVERAGE NUMBER OF AVERAGE
EXERCISE PRICES SHARES IN YEARS EXERCISE PRICE SHARES EXERCISE PRICE
--------------- -------------- ---------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
$ 0.50 - $ 0.50........... 841,220 5.00 $ 0.50 841,220 $ 0.50
$ 1.85 - $ 1.85........... 117,887 5.25 1.85 117,887 1.86
$ 4.57 - $ 4.91........... 692,228 7.48 4.77 489,737 4.71
$ 6.83 - $ 6.83........... 1,317 9.00 6.83 1,317 6.83
$ 8.57 - $ 8.57........... 474,251 9.00 8.57 117,808 8.57
$16.00 - $20.50........... 382,900 9.22 18.19 57,500 19.27
$20.75 - $20.75........... 10,000 9.04 20.75 10,000 20.75
--------- --------- --------- --------- ---------
Total........... 2,519,803.. 7.10 $ 6.03 1,635,469 $ 3.23
========= ========= ========= ========= =========
</TABLE>
15. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from two
sources -- PG&E and the Sacramento Municipal Utility District ("SMUD").
F-36
<PAGE> 91
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Revenues earned from these sources for the years ended, December 31, 1997,
1996 and 1995 were as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
REVENUES: -------- -------- --------
<S> <C> <C> <C>
PG&E....................................... $221,457 $183,531 $112,522
SMUD....................................... 13,223 14,609 12,345
</TABLE>
Accounts receivable at December 31, 1997 and 1996 were as follows (in
thousands):
<TABLE>
<CAPTION>
1997 1996
ACCOUNTS RECEIVABLE: -------- --------
<S> <C> <C> <C>
PG&E....................................... $ 29,631 $ 27,534
SMUD....................................... 1,019 1,137
</TABLE>
Industry restructuring and deregulation (see Note 16, "Regulation and CPUC
Restructuring") will also affect PG&E, the Company's primary customer.
16. COMMITMENTS AND CONTINGENCIES
Capital Projects -- The Company has 1998 commitments of $19.8 million
related to the construction of the Pasadena Power Plant (see Note 3, "Pasadena
Cogeneration Project").
Royalties and Leases -- The Company is committed under several geothermal
leases and right-of-way, easement and surface agreements. The geothermal leases
generally provide for royalties based on production revenue with reductions for
property taxes paid. The right-of-way, easement and surface agreements are based
on flat rates and are not material. Under the terms of certain geothermal
leases, royalties accrue at rates ranging from 7% to 12.5% of steam and effluent
revenue. Certain properties also have net profits and overriding royalty
interests ranging from approximately 1.45% to 28%, which are in addition to the
land royalties. Most lease agreements contain clauses providing for minimum
lease payments to lessors if production temporarily ceases or if production
falls below a specified level.
Expenses under these agreements for the years ended December 31, 1997, 1996
and 1995 are (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Production Royalties.................. $10,803 $10,793 $10,574
Lease payments........................ 222 246 225
</TABLE>
Natural Gas Purchases -- The Company enters into short-term gas purchase
contracts with third parties to supply gas to its gas-fired cogeneration
projects.
Watsonville Operating Lease -- In June 1995, the Company acquired a 14.5
year operating lease (through December 2009) for the 28.5 megawatt natural
gas-fired cogeneration power plant located in Watsonville, California. Under the
terms of the lease, basic and contingent rents are payable each month during the
period from July through December. As of December 31, 1997, future basic rent
payments have remained the same from prior years at $2.9 million for 1996 and
1997, respectively. Future payment from 1998 to 2001 will continue at the
current rate of $2.9 million, and $24.4 million thereafter through December
2009. Contingent rent expense for 1997 and 1996 was $864,000 and $671,000,
respectively. This expense is based on the net of revenues less all operating
expenses, fees, reserve requirements, basic rent and supplemental rent payments.
Of the remaining balance, 60% is payable to the lessor and 40% is payable to the
Company.
F-37
<PAGE> 92
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Office and Equipment Leases -- The Company leases its corporate office,
Santa Rosa office facilities and certain office equipment under noncancellable
operating leases expiring through 2002. Future minimum lease payments under
these leases are (in thousands):
<TABLE>
<S> <C>
1998................................ $1,409
1999................................ 1,211
2000................................ 1,128
2001................................ 564
2002................................ 114
Thereafter.......................... --
------
$4,426
======
</TABLE>
Lease payments are subject to adjustments for the Company's pro rata
portion of annual increases or decreases in building operating costs. In 1997,
1996, and 1995 rent expenses for noncancellable operating leases amounted to
$1.2 million, $1.0 million and $733,000, respectively.
Regulation and CPUC Restructuring -- Electricity and steam sales agreements
with PG&E are regulated by the California Public Utilities Commission ("CPUC").
In December 1995, the CPUC issued a decision which proposed the transition of
the regulated electric generation market to a competitive generation market
beginning January 1, 1998. Since the proposed restructure represented a
widespread impact on the market structure, requiring participation and oversight
of the Federal Energy Regulatory Commission (the "FERC"), the CPUC sought and
built a California consensus coalition which resulted in filings at the FERC
which permitted the CPUC and the FERC to collectively proceed with
implementation of the new competitive market structure. In late 1996,
comprehensive legislation, AB 1890 ("the Bill"), was signed into California law
which adopted the basic tenets of the CPUC electric industry restructure
decision and directed the CPUC to proceed with implementation of restructure
with customer choice of electricity supplier available no later than January 1,
1998. The Bill provided for market power mitigation by utility divestiture of
fossil generation plants, provided a four year transition period for utility
recovery of stranded costs, provided for sanctity of existing qualifying
facility ("QF") contracts with provision for voluntary restructure, established
an electricity rate freeze for the four year transition period for certain
customers, mandated a 10% rate reduction beginning January 1, 1998 and
continuing through the transition period for small commercial and residential
customers financed by issuance of rate reduction bonds, and provided specified
funds for continued public service programs including public interest research
and development and enhancement of in-state renewable energy resources, which
includes geothermal operations. In late 1997, the CPUC and the FERC issued
decisions which provided for January 1, 1998 implementation of the California
Independent Systems Operator ("ISO") responsible for centralized control and
reliable operation of the state-wide electric transmission grid and the Power
Exchange ("PX") responsible for the competitive electric energy auction. In late
1997, CPUC-approved sales of certain utility-owned fossil generation plants were
completed and applications were pending at the CPUC for sales of the remaining
utility-owned California fossil and geothermal power plants. Investor-owned
utilities, though transferring control to the ISO, will continue to own and
collect revenue from their transmission facilities and will continue to be
regulated utility distribution companies ("UDC") for all electric service
providers with default electric supplier responsibility.
In December 1997, mechanics for operation of the ISO and PX were not yet
fully perfected and implementation of deregulation was delayed to April 1, 1998.
The California Energy Commission ("CEC") was directed by the Bill to develop a
competitive mechanism for allocation and distribution of funds made available
for public interest research and development and enhancement of in-state
renewable resources. The CEC, in late 1997, issued its draft guidelines for
selective allocation and distribution of the funds which are to be available
over the four year transition period to a fully competitive electric services
industry. Though the
F-38
<PAGE> 93
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Company believes that implementation of electric industry restructure can
provide significant opportunity for independent power producers, the ultimate
impact of both increased competition and the changing regulatory environment on
the Company's future results from operations is uncertain.
A domestic electricity generating project must be a QF under the FERC
regulations in order to take advantage of certain rate and regulatory incentives
provided by the Public Utility Regulatory Policies Act of 1978, as amended
("PURPA"). PURPA exempts owners of QFs from the Public Utility Holding Company
Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions of the
Federal Power Act (the "FPA") and state laws concerning rate or financial
regulation. PURPA also requires that electric utilities purchase electricity
generated by QFs at a price based on the utility's "avoided cost", and that the
utility sell back-up power to the QF on a non-discriminatory basis. If one of
the projects in which the Company has an interest should lose its status as a
QF, the project would no longer be entitled to the exemptions from PUHCA and the
FPA. This could trigger certain rights of termination under the power sales
agreement, could subject the project to rate regulation as a public utility
under the FPA and state laws and could result in the Company inadvertently
becoming a public utility holding company. The Company believes that each of the
electricity generating projects in which the Company owns an interest currently
meets the requirements under PURPA necessary for QF status.
Litigation
On September 30, 1997, a lawsuit was filed by Indeck North American Power
Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb
plc. and certain other parties, including the Company. Some of Indeck's claims
relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in
Gordonsville Energy L.P. from Northern Hydro Limited and Calpine Auburndale,
Inc.'s acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck is claiming that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. All the defendants filed motions to dismiss such
claims, which are currently pending. The Company believes that the claims of
Indeck are without merit and that the resolution of this matter will not have a
material adverse effect on the Company's financial position or results of
operations.
On February 17, 1998, the Company filed an action in the Superior Court of
California, Sonoma County, seeking injunctive and declaratory relief to prevent
PG&E from unilaterally assigning the Company's steam sales contract to the
prospective winning bidder in PG&E's recently announced auction of its power
plants in The Geysers. On January 14, 1998, PG&E filed an application with the
CPUC pursuant to Public Utilities Code Section 851 ("851 Filing"), in which it
seeks authorization to sell five electric generating plants and related assets.
Included in this proposed sale are The Geysers Geothermal Power Plants
(including Units 13 and 16) and certain of PG&E's fossil fueled steam-electric
generating plants. In PG&E's 851 Filing, PG&E announced its intention to assign
its rights and to delegate its duties under the Company's steam contract to the
successful third party purchaser of the Unit 13 and Unit 16 Power Plants. The
Company has been informed by PG&E that it will attempt to make such assignment
and delegation without first seeking and obtaining the approval and consent of
the Company. The Company is challenging the continued validity of the price term
of the steam sales contract following the proposed divestiture by PG&E of 98% of
its fossil fueled steam-electric generating plants, as the price term of the
steam sales contract is based on a complex formula that reflects PG&E's weighted
average cost of fossil and nuclear fuel from the preceding year.
In a related action, the Company has filed a protest with the CPUC which
raises issues similar to those addressed in the above-referenced lawsuit and, in
addition, challenges certain inaccuracies contained in
F-39
<PAGE> 94
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
portions of PG&E's 851 Filings related to Unit 13 and Unit 16. As no discovery
has been conducted in either matter, nor has any answer been filed in the
lawsuit, the Company is unable to predict the outcome of these cases.
An action was filed against Lockport Energy Associates, L.P. ("LEA") on
August 7, 1997 by New York State Electricity and Gas Company ("NYSEG") in the
Federal District Court for the Northern District of New York. NYSEG has
requested the Court to direct the FERC and the New York Public Service
Commission ("NYPSC"), to modify contract rates to be paid to the Lockport Power
Plant. On October 14, 1997, NYPSC, a named defendant in the NYSEG action, filed
a cross-claim alleging that the FERC violated PURPA and the Federal Power Act by
failing to reform the NYSEG contract which was previously approved by the NYPSC.
LEA continues to vigorously defend this action, although it is unable to predict
the outcome of this case. The Company retains the right to require BUG to
purchase the Company's interest in the Lockport Power Plant for $18.9 million,
less equity distributions received by the Company, at any time before December
19, 2001. In the event the NYSEG's action is successful, the Company may choose
to exercise its right to require BUG to purchase its interest in the Lockport
Power Plant.
There is currently a dispute between Texas-New Mexico Power Company ("TNP")
and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear
Lake Power Plant, regarding certain costs and other amounts that TNP has
withheld from payments due under the power sales agreement. As of December 31,
1997, TNP has withheld approximately $5.4 million related to transmission
charges and has continued to withhold approximately $450,000 per month
thereafter. CLC filed a petition for declaratory order with the Texas Public
Utilities Commission ("Texas PUC") on October 2, 1997 requesting that the Texas
PUC declare that TNP's withholding is in error. This matter is pending before
the Texas PUC. In addition, as of December 31, 1997, TNP has withheld
approximately $4.4 million of standby power charges and has continued to
withhold approximately $270,000 per month thereafter. CLC has filed a lawsuit in
Texas against TNP claiming that TNP is in breach of certain provisions of the
power sales agreement, including the provisions involved in the disputes
described above, and is seeking in excess of $15.0 million in damages. A trial
is scheduled to begin on June 1, 1998. The Company is unable to predict the
outcome of either of these proceedings.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. The Company does not expect that the
outcome of these proceedings will have a material adverse effect on the
Company's financial position or results of operations, although no assurance can
be given in this regard.
F-40
<PAGE> 95
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
17. EARNINGS PER SHARE
The Company adopted SFAS No. 128 as of December 31, 1997. The
reconciliation of the numerators and denominators of the basic and diluted
earnings per share computation are as follows:
<TABLE>
<CAPTION>
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
FOR THE YEAR 1995 (IN THOUSANDS)
<S> <C> <C> <C>
BASIC EARNINGS PER SHARE
Income available to common stockholders............ $ 7,378 10,388 $ 0.71
=======
Common shares issuable upon exercise of stock
options using treasury stock method.............. -- 569
------- -------
DILUTED EARNINGS PER SHARE
Income available to common stockholders plus
assumed conversions.............................. $ 7,378 10,957 $ 0.67
======= ======= =======
FOR THE YEAR 1996
BASIC EARNINGS PER SHARE
Income available to common stockholders............ $18,692 12,903 $ 1.45
=======
Common shares issuable upon exercise of stock
options using treasury stock method.............. -- 886
Common shares outstanding assumed conversion of
preferred stock (1).............................. -- 1,090
------- -------
DILUTED EARNINGS PER SHARE
Income available to common stockholders plus
assumed conversion............................... $18,692 14,879 $ 1.26
======= ======= =======
FOR THE YEAR 1997
BASIC EARNINGS PER SHARE
Income available to common stockholders............ $34,699 19,946 $ 1.74
=======
Common shares issuable upon exercise of stock
options using treasury stock method.............. -- 1,070
------- -------
DILUTED EARNINGS PER SHARE
Income available to common stockholders plus
assumed conversions.............................. $34,699 21,016 $ 1.65
======= ======= =======
</TABLE>
Basic earnings per share for the year ended December 31, 1996 was computed
using the weighted average number of common shares outstanding. Diluted earnings
per share was computed using the weighted average number of common and common
equivalent shares for outstanding stock options. Options to purchase
approximately 385,000 shares of common stock at a weighted average price of
$18.00 per share were outstanding during the fourth quarter of 1997. These
options were not included in the computation of diluted earnings per share
because the options' exercise price was greater than the average market price of
common shares. The change in the way the Company previously reported earnings
per share for financial reporting purposes is in part due to the adoption of
SFAS No. 128 and subsequently, SAB No. 98 on "Computations of Earnings per
Share" which became effective in February 1998.
18. QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
The Company's quarterly operating results have fluctuated in the past and
may continue to do so in the future as a result of a number of factors,
including, but not limited to, the timing and size of acquisitions, the
completion of development projects, the timing and amount of curtailment, and
variations in levels of production. Furthermore, the majority of capacity
payments under certain of the Company's power sales agreements are received
during the months of May through October.
F-41
<PAGE> 96
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
The Company's common stock has been traded on the New York stock exchange
since September 19, 1996. There were 45 common stockholders of record at
December 31, 1997. No dividends were paid for the years ended December 31, 1997
and 1996.
<TABLE>
<CAPTION>
QUARTER ENDED
-------------------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 30
------------- -------------- --------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1997
Total revenue..................................... $76,441 $92,905 $67,744 $39,231
Income from operations............................ $27,154 $43,384 $24,379 $ 2,270
Net income (loss)................................. $10,192 $19,147 $ 9,400 $(4,040)
Basic earnings per share.......................... $ 0.51 $ 0.96 $ 0.47 $ (0.20)
Diluted earnings per share........................ $ 0.48 $ 0.91 $ 0.45 $ (0.20)
Common stock price per share
High............................................ $ 21.25 $ 22.94 $ 20.88 $ 22.75
Low............................................. $ 12.38 $ 16.50 $ 15.75 $ 17.13
1996
Total revenue..................................... $61,663 $70,897 $50,321 $31,673
Income from operations............................ $14,303 $29,097 $16,203 $ 7,188
Net income (loss)................................. $ 3,537 $10,732 $ 4,717 $ (294)
Basic earnings per share.......................... $ 0.18 $ 0.95 $ 0.45 $ (0.03)
Diluted earnings per share........................ $ 0.17 $ 0.76 $ 0.35 $ (0.03)
Common stock price per share
High............................................ $ 20.00 $ 16.38 $ -- $ --
Low............................................. $ 16.00 $ 16.00 $ -- $ --
</TABLE>
F-42
<PAGE> 97
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements of Calpine Corporation and subsidiaries
included in this Form 10-K and have issued our report thereon dated February 10,
1998. Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index of
financial statement schedules are the responsibility of the Company's management
and are presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly state in all material
respects the financial data required to be set forth therein in relation to the
basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
San Jose, California
February 10, 1998
(except for Note 5 as to which the date is February 17, 1998)
F-43
<PAGE> 98
CALPINE CORPORATION
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
DECEMBER 31, 1997 AND 1996
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996
ASSETS -------- --------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................. $(55,070) $ 33,150
Accounts receivable from related parties.................. 6,164 4,534
Accounts receivable....................................... 2,168 5,024
Other current assets...................................... 714 1,603
-------- --------
Total current assets.............................. (46,024) 44,311
Property, plant and equipment, net.......................... 6,617 5,711
Investments in power projects............................... 246,090 141,816
Intercompany receivables.................................... 632,188 302,230
Notes receivable from related parties....................... -- 18,182
Deferred charges............................................ 16,282 8,326
Other assets................................................ 133 122
-------- --------
Total assets...................................... $855,286 $520,698
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 11,699 $ 504
Accrued payroll and related expenses...................... 4,208 3,477
Accrued interest payable.................................. 17,960 6,462
Other current liabilities................................. 3,409 5,385
-------- --------
Total current liabilities......................... 37,276 15,828
Senior Notes................................................ 560,041 285,000
Deferred income taxes, net.................................. 18,013 11,230
Deferred revenue............................................ -- 5,513
-------- --------
Total liabilities................................. 615,330 317,571
Stockholders' equity:
Common stock, $0.001 par value............................ 20 20
Additional paid-in capital................................ 167,542 165,412
Retained earnings......................................... 72,394 37,695
-------- --------
Total stockholders' equity........................ 239,956 203,127
-------- --------
Total liabilities and stockholders' equity........ $855,286 $520,698
======== ========
</TABLE>
The accompanying notes are an integral part of these condensed financial
statements.
F-44
<PAGE> 99
CALPINE CORPORATION
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Revenue:
Service contract revenue from related parties............ $ 43,936 $ 36,582 $ 28,733
Income from unconsolidated investments in power
projects.............................................. 103,898 66,625 32,397
-------- -------- --------
Total revenue.................................... 147,834 103,207 61,130
Cost of revenue:
Service contract expenses................................ 42,014 34,953 27,433
-------- -------- --------
Gross profit............................................... 105,820 68,254 33,697
Project development expenses............................... 7,537 3,867 3,087
General and administrative expenses........................ 16,968 13,651 8,081
-------- -------- --------
Income from operations........................... 81,315 50,736 22,529
Interest expense........................................... 40,790 23,036 10,479
Interest income............................................ (11,470) (4,313) (71)
Other (income) expense..................................... (1,164) 4,257 (306)
-------- -------- --------
Income before provision for income taxes......... 53,159 27,756 12,427
Provision for income taxes................................. 18,460 9,064 5,049
-------- -------- --------
Net income....................................... $ 34,699 $ 18,692 $ 7,378
======== ======== ========
Basic earnings per common share:
Weighted average shares of common stock outstanding...... 19,946 12,903 10,388
Basic earnings per common share.......................... $ 1.74 $ 1.45 $ 0.71
Diluted earnings per common share:
Weighted average shares of common stock outstanding...... 21,016 14,879 10,957
Diluted earnings per common share........................ $ 1.65 $ 1.26 $ 0.67
</TABLE>
The accompanying notes are an integral part of these condensed financial
statements.
F-45
<PAGE> 100
CALPINE CORPORATION
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Net cash used in operating activities................... $(360,783) $(281,828) $ (8,997)
--------- --------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment.......... (1,316) (5,321) (368)
Investments in power projects......................... (4,172) -- (1,262)
Decrease (increase) in notes receivable, net.......... 11,500 2,750 (10,337)
--------- --------- ---------
Net cash provided by (used in) investing activities..... 6,012 (2,571) (11,967)
--------- --------- ---------
Cash flows from financing activities:
Payment of dividend................................... -- -- (800)
Borrowings from line of credit........................ 14,300 46,861 14,000
Repayment of borrowings under line of credit.......... (14,300) (60,861) --
Proceeds from Senior Notes............................ 275,041 180,000 --
Proceeds from issuance of preferred stock............. -- 50,000 --
Proceeds from issuance of common stock................ 1,022 109,208 --
Financing costs....................................... (9,512) (5,688) 279
--------- --------- ---------
Net cash provided by financing activities..... 266,551 319,520 13,479
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents.... (88,220) 35,121 (7,485)
Cash and cash equivalents, beginning of period.......... 33,150 (1,971) 5,514
--------- --------- ---------
Cash and cash equivalents, end of period................ $ (55,070) $ 33,150 $ (1,971)
========= ========= =========
Cash paid during the period for:
Interest.............................................. $ 19,218 $ 19,763 $ 9,945
Income taxes.......................................... $ 9,795 $ 6,947 $ 4,294
</TABLE>
The accompanying notes are an integral part of these condensed financial
statements.
F-46
<PAGE> 101
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
1. ORGANIZATION AND OPERATION OF CALPINE
Calpine Corporation ("Calpine"), a Delaware Corporation, is engaged in the
development, acquisition, ownership and operation of power generation facilities
in the United States. Calpine has ownership interests in and operates geothermal
steam fields, geothermal power generation facilities, and natural gas-fired
cogeneration facilities through subsidiaries and investees.
In July 1996, Calpine's Board of Directors authorized the reincorporation
of Calpine in Delaware in connection with Calpine's initial public offering. In
addition, the Board of Directors approved a stock split of approximately
5.194-for-1. In September 1996, the reincorporation of Calpine and the stock
split became effective. The accompanying financial statements reflect the
reincorporation and the stock split as if such transactions had been effective
for all periods.
For the purposes of these registrant-only financial statements, Calpine's
wholly-owned subsidiaries are accounted for under the equity method and are
included in investments in power projects in the accompanying balance sheets.
These financial statements should be read in conjunction with Calpine
Corporation and Subsidiaries Consolidated Financial Statements.
2. SENIOR NOTES
On July 8, 1997, the Company issued $200.0 million aggregate principal
amount of 8 3/4% Senior Notes Due 2007. Transaction costs of $9.7 million
incurred in connection with the debt offering were capitalized and are included
in Other assets and are amortized over the ten-year life of the 8 3/4% Senior
Notes Due 2007.
On September 10, 1997, the Company issued an additional $75.0 million
aggregate principal amount of 8 3/4% Senior Notes Due 2007. The net proceeds
were for general corporate purposes.
In May and June 1997, the Company executed five interest rate hedging
transactions related to debt. The notional value of the debt was $182.0 million
and was designed to eliminate interest rate risk for the period from May 1997 to
July 1997 when the $200.0 million of 8 3/4% Senior Notes Due 2007 were priced.
These interest rate hedging transactions were designated as a hedge of the
anticipated bond offering, and the resulting $3.0 million cost resulting from
the hedges is being amortized over the life of the bonds. The effective interest
rate on the $275.0 million aggregate principal amount after the hedging
transactions and the amortization of transaction costs was 9.1%.
The 8 3/4% Senior Notes Due 2007 will mature on July 15, 2007. The Company
has no sinking fund or mandatory redemption obligations with respect to the
8 3/4% Senior Notes Due 2007. Interest is payable semi-annually on January 15
and July 15 of each year while the 8 3/4% Senior Notes Due 2007 are outstanding,
commencing on January 15, 1998. Based on the traded yield to maturity, the
approximate fair market value of the 8 3/4% Senior Notes Due 2007 was $280.5
million as of December 31, 1997.
On May 16, 1996, the Company issued $180.0 million aggregate principal
amount of 10 1/2% Senior Notes Due 2006. Transaction costs of $5.1 million
incurred in connection with the public debt offering were recorded as other
assets and are amortized over the ten-year life of the 10 1/2% Senior Notes Due
2006. The effective interest rate of the $180.0 million aggregate principal
amount after the amortization of transaction costs was 10.7%.
The 10 1/2% Senior Notes Due 2006 will mature on May 15, 2006. The Company
has no sinking fund or mandatory redemption obligations with respect to the
10 1/2% Senior Notes Due 2006. Interest is payable semi-annually on May 15 and
November 15. Based on the traded yield to maturity, the approximate fair market
value of the 10 1/2% Senior Notes Due 2006 was $196.2 million as of December 31,
1997.
F-47
<PAGE> 102
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
The 9 1/4% Senior Notes Due 2004 will mature on February 1, 2004. The
Company has no sinking fund or mandatory redemption obligations with respect to
the 9 1/4% Senior Notes Due 2004. Interest is payable semi-annually on February
1 and August 1. Based on the traded yield to maturity, the approximate fair
market value of the 9 1/4% Senior Notes Due 2004 was $108.7 million as of
December 31, 1997. The effective interest rate on the $105.0 million aggregate
principal amount after amortization of transaction costs was 9.6%.
The Senior Note indentures specify that the Company maintains certain
covenants with which the Company was in compliance. The Company may, under
certain circumstances, be limited in its ability to make restricted payments, as
defined, which include dividends and certain purchases and investments, incur
additional indebtedness and engage in certain transactions.
3. NOTES RECEIVABLE
In May 1993, in accordance with the Sumas Cogeneration, L.P. ("Sumas")
partnership agreement, the Company was entitled to receive a distribution of
$1.5 million and Sumas Energy, Inc. ("SEI"), the Company's partner in Sumas, was
required to make a capital contribution of $1.5 million. In order to meet SEI's
$1.5 million capital contribution requirement, the Company loaned $1.5 million
to the sole shareholder of SEI, who in turn loaned the funds to SEI, who in turn
contributed the capital to Sumas. The interest rate on the loan was 20% and was
secured by a security interest in the loan between SEI and its sole shareholder.
The Company received all principal plus accrued interest totaling $2.8 million
in 1997.
In March 1994, the Company loaned $10.0 million to the sole shareholder of
SEI. The interest rate on the loan was 16.25%. The loan was secured by a pledge
to Calpine of SEI's interest in Sumas. The Company deferred the recognition of
interest income from these notes until Sumas generated net income.
In September 1997, the Company entered into a loan agreement with SEI's
sole shareholder wherein the Company agreed to make available a line of credit
up to $15.0 million, the proceeds of which are required to be used to develop a
new project. SEI has guaranteed the payment and performance of obligations under
this agreement and borrowings under the agreement will be collateralized by the
new project and the sole shareholder's 100% interest in SEI. The loan agreement
will expire on December 31, 2003.
During 1997, the $10.0 million loan was sold to a third party. The Company
received all unpaid principal and interest related to both loans and recognized
a total of $6.9 million of the interest income during 1997 (of which $3.5
million was previously deferred). In addition, the Company recorded a $1.1
million gain upon the sale of the $10.0 million loan, which was recorded in
Other (income) expense. In 1996, the Company recognized $2.1 million of interest
income related to the above two loans, which represents the portion of Sumas'
earnings not recognized by the Company related to its equity investment in
Sumas.
4. REVOLVING CREDIT FACILITY AND LINE OF CREDIT
At December 31, 1997 and 1996, Calpine had a $50.0 million credit facility
available with a consortium of commercial lending institutions which include The
Bank of Nova Scotia, ING U.S. Capital Corporation, Sumitomo Bank of California
and Canadian Imperial Bank of Commerce. As of December 31, 1997, the Company had
no borrowings and $9.4 million of letters of credit outstanding. This amount
reflects $6.0 million to secure performance with the Clear Lake Power Plant,
$1.5 million to secure performance under a purchase power agreement, and $1.9
million related to operating expenses at Calpine Monterey Cogeneration Inc.,
("CMCI"). At December 31, 1996, Calpine had no borrowings and $5.9 million of
letters of credit outstanding, which reflected $3.0 million to secure
performance with the Pasadena Power Plant and $2.9 million related to operating
expenses at CMCI. Borrowings bear interest at The Bank of Nova Scotia's base
rate plus an applicable margin or at the London Interbank Offered Rate ("LIBOR")
plus an applicable margin. Interest is paid on the last day of each interest
period for such loans, but not less often than quarterly,
F-48
<PAGE> 103
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
based on the principal amount outstanding during the period for base rate loans,
and on the last day of each applicable interest period, but not less often than
90 days, for LIBOR loans. The credit agreement expires in September 1999. The
credit agreement specified that Calpine maintain certain covenants with which
Calpine was in compliance. Commitment fees related to this line of credit are
charged based on 0.50% of committed unused credit.
At December 31, 1997 and 1996, Calpine had a loan facility with available
borrowings totaling $1.2 million. As of December 31, 1997, Calpine had no
borrowings and $74,000 of letters of credit outstanding. There were no
borrowings and $900,000 of letters of credit outstanding as of December 31,
1996.
5. COMMITMENTS AND CONTINGENCIES
Office and Equipment Leases -- The Company leases its corporate office,
Santa Rosa office facilities and certain office equipment under noncancellable
operating leases expiring through 2002. Future minimum lease payments under
these leases are (in thousands).
<TABLE>
<S> <C>
1998...................................... $1,409
1999...................................... 1,211
2000...................................... 1,128
2001...................................... 564
2002...................................... 114
Thereafter.................................. --
------
$4,426
======
</TABLE>
Lease payments are subject to adjustments for the Company's pro rata
portion of annual increases or decreases in building operating costs. In 1997,
1996, and 1995, rent expenses for noncancellable operating leases amounted to
$1.2 million, $1.0 million and $733,000, respectively.
Regulation and CPUC Restructuring -- Electricity and steam sales agreements
with Pacific Gas and Electric Company ("PG&E") are regulated by the California
Public Utilities Commission ("CPUC"). In December 1995, the CPUC issued a
decision which proposed the transition of the regulated electric generation
market to a competitive generation market beginning January 1, 1998. Since the
proposed restructure represented a widespread impact on the market structure
requiring participation and oversight of the Federal Energy Regulatory
Commission ("the FERC"), the CPUC sought and built a California consensus
coalition which resulted in filings at the FERC which permitted the CPUC and the
FERC to collectively proceed with implementation of the new competitive market
structure. In late 1996, comprehensive legislation, (AB 1890 (the "Bill")), was
signed into California law which adopted the basic tenets of the CPUC electric
industry restructure decision and directed the CPUC to proceed with
implementation of restructure with customer choice of electricity supplier
available no later than January 1, 1998. The Bill provided for market power
mitigation by utility divestiture of fossil generation plants, provided a four
year transition period for utility recovery of stranded costs, provided for
sanctity of existing contracts with provision for voluntary restructure,
established an electricity rate freeze for the four year transition period,
mandated a 10% rate reduction beginning January 1, 1998 and continuing through
the transition period for small commercial and residential customers financed by
issuance of rate reduction bonds, and provided specified funds for continued
public service programs including public interest research and development and
enhancement of in-state renewable energy resources, which includes geothermal
operations. In late 1997 the CPUC and FERC issued decisions which provided for
the January 1, 1998 implementation of the California Independent Systems
Operator ("ISO"), responsible for centralized control and reliable operation of
the state-wide electric transmission grid, and the Power Exchange ("PX"),
responsible for the competitive electric energy auction. In late 1997,
CPUC-approved sales of certain utility-owned fossil generation plants were
completed and applications were pending at the CPUC for sales of the remaining
utility-owned
F-49
<PAGE> 104
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
California fossil and geothermal power plants. Investor-owned utilities, though
transferring control to the ISO, will continue to own and collect revenue from
their transmission facilities and will continue to be regulated utility
distribution companies ("UDC") for all electric service providers with default
electric supplier responsibility.
In December 1997, mechanics for operation of the ISO and PX were not yet
fully perfected and implementation of deregulation was delayed to April 1, 1998.
The California Energy Commission ("CEC") was directed by the Bill to develop a
competitive mechanism for allocation and distribution of funds made available
for public interest research and development and enhancement of in-state
renewable resources. The CEC in late 1997 issued its draft guidelines for
selective allocation and distribution of the funds which are to be available
over the four year transition period to a fully competitive electric services
industry. Though Calpine believes that implementation of electric industry
restructure can provide significant opportunity for independent power producers,
the ultimate impact of both increased competition and the changing regulatory
environment on Calpine's future results from operations is uncertain.
A domestic electricity generating project must be a qualifying facility
("QF") under FERC regulations in order to take advantage of certain rate and
regulatory incentives provided by the Public Utility Regulatory Policies Act of
1978, as amended ("PURPA"). PURPA exempts owners of QFs from the Public Utility
Holding Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most
provisions of the Federal Power Act ("FPA") and state laws concerning rate or
financial regulation. PURPA also requires that electric utilities purchase
electricity generated by QFs at a price based on the utility's "avoided cost",
and that the utility sell back-up power to the QF on a non-discriminatory basis.
If one of the projects in which Calpine has an interest should lose its status
as a QF, the project would no longer be entitled to the exemptions from PUHCA
and the FPA. This could trigger certain rights of termination under the power
sales agreement, could subject the project to rate regulation as a public
utility under the FPA and state laws and could result in Calpine inadvertently
becoming a public utility holding company. Calpine believes that each of the
electricity generating projects in which Calpine owns an interest currently
meets the requirements under PURPA necessary for QF status.
LITIGATION
On September 30, 1997, a lawsuit was filed by Indeck North American Power
Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb
plc. and certain other parties, including the Company. Some of Indeck's claims
relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in
Gordonsville Energy L.P. from Northern Hydro Limited and Calpine Auburndale,
Inc.'s acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck is claiming that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. All the defendants has filed motions to dismiss such
claims, which are currently pending. Calpine believes that the claims of Indeck
are without merit and that the resolution of this matter will not have a
material adverse effect on its financial position or results of operations.
On February 17, 1998, Calpine filed an action in the Superior Court of
California, Sonoma County, seeking injunctive and declaratory relief to prevent
PG&E from unilaterally assigning Calpine's steam sales contract to the
prospective winning bidder in PG&E's recently announced auction of its power
plants in The Geysers. On January 14, 1998, PG&E filed an application with the
CPUC pursuant to Public Utilities Code Section 851 ("851 Filing"), in which it
seeks authorization to sell five electric generating plants and related assets.
Included in this proposed sale are The Geysers Geothermal Power Plants
(including Units 13 and 16) and certain of PG&E's fossil fueled steam-electric
generating plants. In PG&E's 851 Filing, PG&E
F-50
<PAGE> 105
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
announced its intention to assign its rights and to delegate its duties under
Calpine's steam contract to the successful third party purchaser of the Unit 13
and Unit 16 Power Plants. Calpine has been informed by PG&E that it will attempt
to make such assignment and delegation without first seeking and obtaining the
approval and consent of Calpine. Calpine is challenging the continued validity
of the price term of the steam sales contract following the proposed divestiture
by PG&E of 98% of its fossil fueled steam-electric generating plants, as the
price term of the steam sales contract is based on a complex formula that
reflects PG&E's weighted average cost of fossil and nuclear fuel from the
preceding year.
In a related action, Calpine and CGC have filed a protest with the CPUC
which raises issues similar to those addressed in the above-referenced lawsuit
and, in addition, challenges certain inaccuracies contained in portions of
PG&E's 851 Filings related to Unit 13 and Unit 16. As no discovery has been
conducted in either matter, nor has any answer been filed in the lawsuit,
Calpine is unable to predict the outcome of these cases.
An action was filed against Lockport Energy Associates, L.P. ("LEA") on
August 7, 1997 by New York State Electricity and Gas Company ("NYSEG") in the
Federal District Court for the Northern District of New York. NYSEG has
requested the Court to direct the Federal Energy Regulatory Commission (the
"FERC") and the New York Public Service Commission ("NYPSC"), to modify contract
rates to be paid to the Lockport Power Plant. On October 14, 1997, NYPSC, a
named defendant in the NYSEG action, filed a cross-claim alleging that the FERC
violated PURPA and the Federal Power Act by failing to reform the NYSEG contract
which was previously approved by the NYPSC. LEA continues to vigorously defend
this action, although it is unable to predict the outcome of this case. Calpine
retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase
Calpine's interest in the Lockport Power Plant for $18.9 million, less equity
distributions received by Calpine, at any time before December 19, 2001. In the
event the NYSEG's action is successful, Calpine may choose to exercise its right
to require BUG to purchase its interest in the Lockport Power Plant.
There is currently a dispute between Texas-New Mexico Power Company ("TNP")
and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear
Lake Power Plant, regarding certain costs and other amounts that TNP has
withheld from payments due under the power sales agreement. As of December 31,
1997, TNP has withheld approximately $5.4 million related to transmission
charges and has continued to withhold approximately $450,000 per month
thereafter. CLC filed a petition for declaratory order with the Texas Public
Utilities Commission ("Texas PUC") on October 2, 1997 requesting that the Texas
PUC declare that TNP's withholding is in error. This matter is pending before
the Texas PUC. In addition, as of December 31, 1997, TNP has withheld
approximately $4.4 million of standby power charges and has continued to
withhold approximately $270,000 per month thereafter. CLC has filed a lawsuit in
Texas against TNP claiming that TNP is in breach of certain provisions of the
power sales agreement, including the provisions involved in the disputes
described above, and is seeking in excess of $15.0 million in damages. A trial
is scheduled to begin on June 1, 1998. Calpine is unable to predict the outcome
of either of these proceedings.
Calpine and its affiliates are involved in various other claims and legal
actions arising out of the normal course of business. Calpine does not expect
that the outcome of these proceedings will have a material adverse effect on
their financial position or results of operations, although no assurance can be
given in this regard.
F-51
<PAGE> 106
CALPINE CORPORATION
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
ADDITIONS
--------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COSTS AND OTHER END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
----------- ------------ ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserve for capitalized costs.............. $ 1,838 $ -- $ -- $(1,600) $ 238
Allowance for uncollectible accounts....... 238 -- -- -- 238
</TABLE>
FOR THE YEAR ENDED DECEMBER 31, 1996
<TABLE>
<CAPTION>
ADDITIONS
--------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COSTS AND OTHER END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
----------- ------------ ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserve for capitalized costs.............. $ 1,838 $ -- $ -- $ -- $ 1,838(1)
Allowance for uncollectible accounts....... 238 -- -- -- 238
</TABLE>
FOR THE YEAR ENDED DECEMBER 31, 1995
<TABLE>
<CAPTION>
ADDITIONS
--------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COSTS AND OTHER END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
----------- ------------ ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserve for capitalized costs.............. $ 1,838 $ -- $ -- $ -- $ 1,838(1)
Allowance for uncollectible accounts....... 238 -- -- -- 238
</TABLE>
- ---------------
(1) Provision for write-off of project development expenses.
F-52
<PAGE> 107
INDEPENDENT AUDITOR'S REPORT
To the Partners
Sumas Cogeneration Company, L.P. and Subsidiary
We have audited the accompanying consolidated balance sheet of Sumas
Cogeneration Company, L.P. and Subsidiary as of December 31, 1997 and 1996, and
the related consolidated statements of income, changes in partners' deficit, and
cash flows for each of the three years ended December 31, 1997. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the consolidated financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the consolidated financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
consolidated financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Sumas
Cogeneration Company, L.P. and Subsidiary as of December 31, 1997 and 1996, and
the results of their operations and cash flows for each of the three years ended
December 31, 1997, in conformity with generally accepted accounting principles.
MOSS ADAMS LLP
Everett, Washington
January 22, 1998
F-53
<PAGE> 108
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEET
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1997 1996
------------ ------------
<S> <C> <C>
Current assets
Cash and cash equivalents................................. $ 208,776 $ 317,196
Current portion of restricted cash and cash equivalents... 6,094,892 5,787,121
Accounts receivable....................................... 4,502,790 4,605,135
Prepaid expenses.......................................... 181,048 220,130
------------ ------------
Total current assets.............................. 10,987,506 10,929,582
Restricted cash and cash equivalents,....................... 6,214,000 15,666,647
Property, plant and equipment, at cost, net................. 90,459,854 91,737,933
Other assets................................................ 10,819,238 10,938,732
------------ ------------
Total assets...................................... $118,480,598 $129,272,894
============ ============
LIABILITIES AND PARTNERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities.................. 2,780,693 2,988,207
Related party distributions and payables.................. 490,676 476,390
National Energy Systems Company payable................ 1,415 1,490
Partner distributions.................................. 1,736,612 3,517,491
Current portion of long-term debt......................... 4,200,000 3,600,000
------------ ------------
Total current liabilities......................... 9,209,396 10,583,578
Long-term debt, net of current portion...................... 129,200,004 113,400,003
Future removal and site restoration costs................... 731,184 679,600
Deferred income taxes....................................... 396,926 988,400
Commitments................................................. -- --
Partners' equity (deficit).................................. (21,056,912) 3,621,313
------------ ------------
Total liabilities and partners' equity............ $118,480,598 $129,272,894
============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-54
<PAGE> 109
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Revenues
Power sales.................................... $ 38,309,558 $ 43,488,465 $ 30,603,018
Natural gas sales, net......................... 2,483,862 434,611 893,690
Other.......................................... -- 169,146 29,146
------------ ------------ ------------
Total revenues......................... 40,793,420 44,092,222 31,525,854
------------ ------------ ------------
Costs and expenses
Operating and production costs................. 11,211,812 16,852,253 18,493,245
Depletion, depreciation and amortization....... 6,898,111 5,702,310 6,965,496
General and administrative..................... 1,949,365 2,481,470 1,400,129
------------ ------------ ------------
Total costs and expenses............... 20,059,288 25,036,033 26,858,870
------------ ------------ ------------
Income from operations........................... 20,734,132 19,056,189 4,666,984
------------ ------------ ------------
Other income (expense)
Interest income................................ 1,190,133 406,537 490,071
Interest expense............................... (10,782,823) (10,678,618) (11,006,056)
Other expense.................................. (68,258) (133,958) (60,664)
------------ ------------ ------------
Total other expense.................... (9,660,948) (10,406,039) (10,576,649)
------------ ------------ ------------
Income (loss) before provision for income
taxes.......................................... 11,073,184 8,650,150 (5,909,665)
Provision for income taxes....................... 525,642 (155,951) (188,387)
------------ ------------ ------------
Net income (loss)...................... $ 11,598,826 $ 8,494,199 $ (6,098,052)
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-55
<PAGE> 110
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
<TABLE>
<S> <C>
Partners' Equity, December 31, 1994......................... $ 5,523,136
Net loss.................................................... (6,098,052)
------------
Partners' Deficit, December 31, 1995........................ (574,916)
Net income.................................................. 8,494,199
Distributions to partners................................... (4,297,970)
------------
Partners' Equity, December 31, 1996......................... 3,621,313
Net income.................................................. 11,598,826
Distributions to partners................................... (36,277,051)
------------
Partners' Deficit, December 31, 1997........................ $(21,056,912)
============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-56
<PAGE> 111
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Cash flows from operating activities
Net income (loss).............................. $ 11,598,826 $ 8,494,199 $ (6,098,052)
Adjustments to reconcile net income (loss) to
net cash from operating activities
Depletion, depreciation and amortization.... 6,898,111 6,571,522 6,965,496
Deferred income taxes....................... (591,474) 80,600 134,000
Change in operating assets and liabilities
accounts receivable....................... 102,345 (1,514,922) 1,017,993
Prepaid expenses............................ 39,082 2,698 9,497
Accounts payable and accrued liabilities.... (155,930) 1,114,029 (1,407,621)
Related party distributions and payables.... 14,211 (437,524) 425,479
------------ ------------ ------------
Net cash from operating activities..... 17,905,171 14,310,602 1,046,792
------------ ------------ ------------
Cash flows from investing activities
Decrease (increase) in restricted cash and cash
equivalents................................. 9,144,876 (10,498,126) 2,908,466
Acquisition of property, plant and equipment... (3,772,579) (913,970) (3,710,025)
Other assets................................... (1,727,958) -- --
------------ ------------ ------------
Net cash from investing activities..... 3,644,339 (11,412,096) (801,559)
------------ ------------ ------------
Cash flows from financing activities
Repayment of long-term debt.................... (3,600,000) (2,000,000) (400,000)
Proceeds from long-term debt................... 20,000,000 -- --
Distributions to partners...................... (38,057,930) (780,479) --
------------ ------------ ------------
Net cash from financing activities..... (21,657,930) (2,780,479) (400,000)
------------ ------------ ------------
Net increase (decrease) in cash and cash
equivalents.................................... (108,420) 118,027 (154,767)
Cash and cash equivalents, beginning of year..... 317,196 199,169 353,936
------------ ------------ ------------
Cash and cash equivalents, end of year........... 208,776 317,196 199,169
------------ ------------ ------------
Supplementary disclosure of cash flow information
Cash paid for interest during the year......... $ 10,782,823 $ 10,678,618 $ 11,006,056
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-57
<PAGE> 112
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General -- Sumas Cogeneration Company, L.P. (the Partnership) is a Delaware
limited partnership formed in 1991 between Sumas Energy, Inc. ("SEI"), the
general partner which currently holds a 50% interest in the profits and losses
of the Partnership, and Whatcom Cogeneration Partners, L.P. ("Whatcom"), the
sole limited partner which holds the remaining 50% Partnership interest. In
addition, Whatcom is entitled certain additional distribution amounts through
June 30, 2001, representing 20% of forecasted cash flows. Whatcom is owned
through affiliated companies by Calpine Corporation ("Calpine"). The Partnership
has a wholly-owned Canadian subsidiary, ENCO Gas, Ltd. ("Enco"), which is
incorporated in New Brunswick, Canada. The consolidated financial statements
include the accounts of the Partnership and ENCO (collectively, the Company).
All intercompany profits, transactions and balances have been eliminated in
consolidation.
The Partnership owns and operates an electrical generation facility (the
"Generation Facility") in Sumas, Washington. The Generation Facility is a
natural gas-fired combined cycle electrical generation plant which has a
nameplate capacity of approximately 125 megawatts. Commercial operation of the
Generation Facility commenced in April 1993. The Generation Facility includes a
lumber dry kiln facility and a 3.5 mile private natural gas pipeline.
ENCO owns and operates a portfolio of natural gas reserves in British
Columbia and Alberta, Canada, which provide a dedicated fuel supply for the
Generation Facility (collectively, the Project). ENCO produces and supplies
natural gas to the Generation Facility with off-sales to third parties. The
Generation Facility also receives a portion of its fuel under contracts with
third parties.
The Partnership produces and sells its entire electrical output to Puget
Sound Energy, Inc. ("Puget") under a 20-year electricity sales contract. The
electricity sales contract provides for the sale of electrical output at stated
prices through 2012. The stated price includes a fixed and a variable component.
The fixed and variable components are stated amounts per kilowatt hour in each
contract year. The variable component is adjusted annually based on an index of
inflation. The electricity sales contract also provides for the electrical
output of the Generation Facility to be displaced when the cost of Puget's
replacement power is less than the Company's incremental power generation costs.
The Company receives a share of the net savings from displacement. During 1997,
the Generation Facility was displaced approximately six months. Under the
electricity sales contract, the Partnership is required to be certified as a
qualifying cogeneration facility as established by the Public Utility Regulatory
Policy Act of 1978, as amended, and as administered by the Federal Energy
Regulatory Commission.
The Generation Facility produced and sold kilowatt hours of electricity to
Puget as follows:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, KILOWATT HOURS
------------ --------------
<S> <C>
1997..................... 439,370,000
1996..................... 1,031,900,000
1995..................... 1,026,000,000
</TABLE>
The Partnership leases a kiln facility and sells steam under a 20-year
agreement for the purchase and sale of steam and lease of the kiln (see Note 6)
to Socco, Inc. ("Socco"), a custom lumber drying operation owned by an affiliate
of the Partnership. Steam use requirements under the agreement with Socco were
established to maintain the qualifying cogeneration facility status of the
Generation Facility.
The Partnership -- SEI assigned all its rights, title, and interest in the
Project, including the Puget contract, to the Partnership in exchange for its
Partnership interest. During 1997, all preferential distributions were fully
paid and the Partnership Agreement was amended. SEI and Whatcom are both
currently entitled to a 50% interest in the profits, losses and cash flow of the
Partnership. In addition, Whatcom is entitled to an additional allocation of
profits, losses and cash flows of a stated amount equal to 20% of forecasted
cash flows
F-58
<PAGE> 113
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
for the period through June 30, 2001. After Whatcom has received cumulative
distributions representing a fixed rate-of-return of 24.5% on its equity
investment, exclusive of certain of the preferential distributions referred to
above, SEI's share of operating distributions will increase to 99.9% and
Whatcom's share of operating distributions will decrease to 0.1%.
Distributions -- Distributions of operating cash flows are permitted
quarterly after required deposits are made and minimum cash balances are met,
and are subject to certain other restrictions. For the year ended December 31,
1997, distributions totaling $36,277,051 were paid or accrued. On January 30,
1998, the December 31, 1997 accrued distributions in the amount of $1,736,612
will be paid. For the year ended December 31, 1996, distributions totaling
$4,297,970 were paid or accrued. On January 31, 1997, the December 31, 1996
accrued distributions in the amount of $3,517,491 were paid. No distributions
were paid or accrued for the year ended December 31, 1995.
Revenue recognition -- Revenue from the sale of electricity is recognized
based on kilowatt hours generated and delivered to Puget at contractual rates.
Revenue from displacement is recognized in the period to which the displacement
relates. Revenue from the sale of natural gas is recognized based on volumes
delivered to customers at contractual delivery points and rates. The costs
associated with the generation of electricity and the delivery of gas, including
operating and maintenance costs, gas transportation and royalties, are
recognized in the same period in which the related revenue is earned and
recorded.
Gas acquisition and development costs -- ENCO follows the full cost method
of accounting for gas acquisition and development expenditures, wherein all
costs related to the development of gas reserves in Canada are initially
capitalized. Costs capitalized include land acquisition costs, geological and
geophysical expenditures, rentals on undeveloped properties, cost of drilling
productive and nonproductive wells, and well equipment. Gains or losses are not
recognized upon disposition or abandonment of natural gas properties unless a
disposition or abandonment would significantly alter the relationship between
capitalized costs and proven reserves.
All capitalized costs of gas properties, including the estimated future
costs to develop proven reserves, are depleted using the unit-of-production
method based on estimated proven gas reserves as determined by independent
engineers. ENCO has not assigned any value to its investment in unproven gas
properties and, accordingly, no costs have been excluded from capitalized costs
subject to depletion.
Costs subject to depletion under the full cost include estimated future
costs of dismantlement and abandonments of ENCO of $3,560,000 in 1997,
$3,718,000 in 1996 and $3,748,000 in 1995. This includes the cost of production
equipment removal and environmental cleanup based upon current regulations and
economic circumstances. The provisions for future removal and site restoration
costs of $168,000 in 1997, $177,000 in 1996 and $193,000 in 1995 are included in
depletion expense.
Capitalized costs are subject to a ceiling test which limits such costs to
the aggregate of the net present value of the estimated future cash flows from
the related proven gas reserves. The ceiling test calculation is made by
estimating the future net cash flows, based on current economic operating
conditions, plus the lower of cost or fair market value of unproven reserves,
and discounting those cash flows at an annual rate of 10%.
Joint venture accounting -- A significant portion of ENCO's natural gas
production activities are conducted jointly with others and, accordingly, these
consolidated financial statements reflect only ENCO's proportionate interest in
such activities.
Foreign exchange gains and losses -- Foreign exchange gains and losses as a
result of translating Canadian dollar transactions and Canadian dollar
denominated cash, accounts receivable and accounts payable transactions are
recognized in the statement of income.
F-59
<PAGE> 114
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
Cash and cash equivalents -- For purposes of the statement of cash flows,
cash and cash equivalents consist of cash and short-term investments in highly
liquid instruments such as certificates of deposit, money market accounts and
U.S. treasury bills with an original maturity of three months or less.
Concentration of credit risk -- Financial instruments, which potentially
subject the Company to concentrations of credit risk, consist primarily of cash
and short-term investments in highly liquid instruments such as certificates of
deposit, money market accounts and U.S. treasury bills with maturities of three
months or less, and accounts receivable. The Company's cash and cash equivalents
are primarily held with two financial institutions. Accounts receivable are
primarily due from Puget.
Depreciation -- The Company provides for depreciation of property, plant
and equipment using the straight-line method over estimated useful lives which
range from 7 to 40 years for plant and equipment and 3 to 7 years for furniture
and fixtures.
Amortization of other assets -- The Company provides for amortization of
other assets using the straight-line method as follows:
<TABLE>
<S> <C>
Organization, start-up and development costs... 5 - 30 years
Financing costs................................ 10 - 15 years
Gas contract costs............................. 20 years
</TABLE>
Income taxes -- Profits or losses of the Partnership are allocated directly
to the partners for income tax purposes. ENCO is subject to Canadian income
taxes and accounts for income taxes on the liability method. The liability
method recognizes the amount of tax payable at the date of the consolidated
financial statements, as a result of all events that have been recognized in the
consolidated financial statements, as measured by currently enacted tax laws and
rates. Deferred income taxes are provided for temporary differences in
recognition of revenues and expenses for financial and income tax reporting
purposes.
Use of estimates -- The preparation of the consolidated financial
statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the amounts reported in
the consolidated financial statements and accompanying notes. Actual results
could differ from those estimates.
Reclassifications -- Certain 1996 amounts have been reclassified to conform
with the 1997 presentation.
2. PROPERTY, PLANT AND EQUIPMENT
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Land and land improvements.............. $ 381,071 $ 381,071
Plant and equipment..................... 84,888,500 84,152,257
Acquisition of gas properties, including
development thereon................... 28,691,894 25,838,035
Furniture and fixtures.................. 221,394 211,116
------------ ------------
114,182,859 110,582,479
Less accumulated depreciation and
depletion............................. 23,723,005 18,844,546
------------ ------------
Total.............................. $ 90,459,854 $ 91,737,933
============ ============
</TABLE>
Depreciation expense was $3,188,859 in 1997, $3,159,774 in 1996 and
$3,316,748 in 1995. Depletion expense was $1,861,800 in 1997, $1,606,000 in 1996
and $1,843,000 in 1995.
F-60
<PAGE> 115
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
3. OTHER ASSETS
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Organization, start-up and development costs.... $ 4,568,404 $ 4,844,015
Financing costs............................... 4,394,946 3,909,886
Gas contract costs............................ 1,855,888 2,184,831
------------ ------------
Total................................. $ 10,819,238 $ 10,938,732
============ ============
</TABLE>
4. LONG-TERM DEBT
The Partnership and ENCO have loan agreements with The Prudential Insurance
Company of America ("Prudential") and Credit Suisse First Boston ("Credit
Suisse"), (collectively, "the Lenders"). Through September 1996, Credit Suisse
was an affiliate of Whatcom. On September 30, 1997, the Partnership entered into
a new additional loan agreement with the Lenders, the Secured Subordinated Loan
(the Subordinated Loan) and made certain minor amendments to its existing Term
Loans. The Subordinated Loan provided an additional $20 million in loans and a
$1 million line of credit facility. At December 31, 1997 and 1996, amounts
outstanding under the loan agreements, by entity, were as follows:
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Sumas Cogeneration Company, L.P.
Term Loan............................. $ 89,926,204 $ 92,781,003
Sumas Cogeneration Company, L.P.
Subordinated Loan..................... 20,000,000 --
ENCO Gas, Ltd........................... 23,473,800 24,219,000
------------ ------------
133,400,004 117,000,003
Less current portion.................... 4,200,000 3,600,000
------------ ------------
Total......................... $129,200,004 $113,400,003
============ ============
</TABLE>
Scheduled annual principal payments under the loan agreements as of
December 31, 1997 are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
------------ ------------
<S> <C>
1998......................... $ 4,200,000
1999......................... 5,400,000
2000......................... 6,900,000
2001......................... 12,600,000
2002......................... 15,000,000
Thereafter................... 89,300,004
------------
Total.............. $133,400,004
============
</TABLE>
The Partnership's loans are comprised of the Term Loans and the
Subordinated Loans. The Subordinated Loans were entered into on September 30,
1997. The Partnership's Term Loans are comprised of a fixed rate loan in the
original amount of $55,510,000 and a variable rate loan in the original amount
of $39,650,000. Interest is payable quarterly on the fixed rate loan at a rate
of 10.35%. Interest on the variable rate loan is payable monthly at either the
London Interbank Offered Rate ("LIBOR"), certificate of deposit rate or Credit
Suisse's base rate, plus an applicable margin which ranges from 0.5% to 1.25% as
stated in the loan agreement. During the year ended December 31, 1997, interest
rates on the variable rate loan ranged from 6.66% to 7.31%. The Term Loans
mature in May 2008.
The Partnership's Subordinated Loans are comprised of a fixed rate loan in
the original amount of $12,000,000, a variable rate loan in the original amount
of $8,000,000 and a Revolving Line of Credit in the
F-61
<PAGE> 116
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
amount of $1,000,000. Interest is payable quarterly on the fixed rate loan at a
rate of 7.85%. Interest is payable monthly on the variable rate loan at either
the LIBOR, certificate of deposit rate or Credit Suisse's base rate, plus an
applicable margin which ranges from 1.00% to 1.75%. During the period from
September 30, 1997 to December 31, 1997, interest rates on the variable rate
Subordinated Loan ranged from 7.16% to 7.19%. The Subordinated Loans mature in
May 2008. The Revolving Line of Credit is renewable annually at the discretion
of the Lenders and is to be used for working capital purposes. Interest is
payable monthly at either the LIBOR, certificate of deposit rate or Credit
Suisse's base rate, plus an applicable margin which ranges from 1.00% to 1.75%.
Through December 31, 1997 no borrowings were made under the Revolving Line of
Credit.
ENCO's loans are comprised of a fixed rate loan in the original amount of
$14,490,000 and a variable rate loan in the original amount of $10,350,000.
Interest is payable quarterly on the fixed rate loan at a rate of 9.99%.
Interest on the variable rate loan is payable monthly at either the LIBOR,
certificate of deposit rate or Credit Suisse's base rate, plus an applicable
margin which ranges from .5% to 1.25% as stated in the loan agreement. During
the year ended December 31, 1997, interest rates on the variable rate loan
ranged from 6.66% to 7.31%. The loans mature in May 2008.
The Partnership pays Prudential an agency fee of $50,000 per year until the
loans mature. The Partnership pays Credit Suisse an agency fee of $40,000 per
year, adjusted annually by an inflation index, until the loans mature. The loans
are collateralized by substantially all the Company's assets and interests in
the Project. Additionally, the Company's rights under all contractual agreements
are assigned as collateral. The Partnership and ENCO loans are
cross-collateralized and contain cross-default provisions.
Under the terms of the loan agreements and the deposit and disbursement
agreements with the Lenders, the Company is required to establish and fund
certain accounts held by Credit Suisse and Royal Trust as security agents. The
accounts require specified minimum deposits and funding levels to meet current
and future operating, maintenance and capital costs, and to provide certain
other reserves for payment of principal, interest and other contingencies. These
accounts are presented as restricted cash and cash equivalents and include cash,
certificates of deposit, money market accounts and U.S. treasury bills, all with
maturities of 3 months or less. The current portion of restricted cash and cash
equivalents is based on the amount of current liabilities for obligations which
may be funded from the restricted accounts. The balance of restricted cash and
cash equivalents has been classified as a non-current asset.
5. INCOME TAXES
The provision for income taxes represents Canadian taxes which consist of
the following:
<TABLE>
<CAPTION>
1997 1996 1995
--------- -------- --------
<S> <C> <C> <C>
Current
Federal large corporation tax............. $ 30,708 $ 41,340 $ 34,625
British Columbia capital taxes............ 35,124 34,011 19,762
65,832 75,351 54,387
Deferred.................................. (591,474) 79,744 135,400
(525,642) 155,095 189,787
Utilization of loss carryforwards for
Canadian income tax purposes............ -- -- 47,700
Reduction of (increase) in Canadian loss
carryforwards due to foreign exchange
and other adjustments................... -- 856 (49,100)
--------- -------- --------
$(525,642) $155,951 $188,387
========= ======== ========
</TABLE>
F-62
<PAGE> 117
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
The principal sources of temporary differences resulting in deferred tax
assets and liabilities are as follows:
<TABLE>
<CAPTION>
1997 1996
----------- -----------
<S> <C> <C>
Deferred tax asset
Canadian net operating loss carryforwards........... $(1,906,396) $ (919,400)
Deferred tax liabilities
Acquisition and development costs of gas
Deducted for tax purposes in excess of
amounts...................................... -- --
Deducted for financial reporting purposes...... 2,303,322 1,907,800
----------- -----------
Net deferred tax liability................ $ 396,926 $ 988,400
=========== ===========
</TABLE>
The Company believes, based upon available information, that all deferred
assets will be realized in the normal course of business and no valuation
allowance is necessary.
The provision for income taxes differs from the Canadian statutory rate
principally due to the following:
<TABLE>
<CAPTION>
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Canadian statutory rate............. 44.62% 44.62% 44.62%
Income taxes based on statutory
rate.............................. $ (887,037) $ (45,824) $ (33,852)
Capital taxes, net of deductible
portion........................... 49,710 60,175 47,028
Non-deductible provincial royalties,
net of resource allowance......... 216,931 123,464 95,671
Depletion on gas properties with no
tax basis......................... 33,436 36,488 44,641
Foreign exchange adjustments........ 63,931 16,362 14,860
Other............................... (2,613) (35,570) 21,439
----------- ----------- -----------
$ (525,642) $ 155,095 $ 189,787
=========== =========== ===========
</TABLE>
As of December 31, 1997, ENCO has non-capital loss carryforwards of
approximately $4,273,000, which may be applied against taxable income of future
periods which expire as follows:
<TABLE>
<S> <C>
1999........................... $1,518,000
2000........................... 233,000
2003........................... 244,000
2004........................... 2,278,000
</TABLE>
6. RELATED PARTY TRANSACTIONS AND COMMITMENTS
Administrative services -- As managing partner of the Partnership, SEI
receives a fee of $250,000 per year through December 1995 and $300,000 per year
for periods after December 1995. The fee is subject to annual adjustment based
upon an inflation index. Approximately $333,000 in 1997, $311,000 in 1996 and
$258,000 in 1995 was paid to SEI under this agreement.
Operating and maintenance services -- The Partnership has an operating and
maintenance agreement with a related party to operate, repair and maintain the
Project. For these services, the Partnership pays a fixed fee of $1,140,000 per
year adjustable based on the Consumer Price Index, an annual base fee of
$150,000 per year, also adjustable based on the Consumer Price Index, and
certain other reimbursable expenses as defined in the agreement. In addition,
the agreement provides for an annual performance bonus of up to $400,000,
adjustable based on the Consumer Price Index, based on the achievement of
certain annual performance levels. Payment of the performance bonus is
subordinated to the payment of operating expenses, debt service and required
deposits, and minimum balances under the loan agreements, and deposit and
disbursement agreements. This agreement expires on the date Whatcom receives its
24.5% cumulative return or the tenth
F-63
<PAGE> 118
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
anniversary of the Project completion date, subject to renewal terms.
Approximately $2,074,000 in 1997, $2,014,000 in 1996 and $2,031,000 in 1995 was
earned under this agreement.
Thermal energy and kiln lease -- The Partnership has a 20-year thermal
energy and kiln lease agreement with Socco. Under this agreement, Socco leases
the premises and the kiln and purchases certain amounts of thermal energy
delivered to dry lumber. Income recorded from Socco was approximately $9,000 in
1996 and $19,000 in 1995.
Consulting services -- ENCO has an agreement with National Energy Systems
Company ("NESCO"), an affiliate of SEI, to provide consulting services for
$8,000 per month, adjustable based upon an inflation index. The agreement
automatically renews for one-year periods unless written notice of termination
is served by either party. Approximately $119,000 in 1997, $107,000 in 1996 and
$100,000 in 1995 was paid under this agreement.
Fuel supply and purchase agreements -- The Partnership has a fixed price
natural gas sale and purchase agreement with ENCO. The agreement requires ENCO
to deliver up to a maximum daily contract quantity of 12,000 mmbtu's of natural
gas per day which may be increased to 24,000 mmbtu's per day in accordance with
the agreement. Partnership payments to ENCO under the agreement are eliminated
in consolidation. The agreement expires on the twentieth anniversary of the date
of commercial operation.
The Partnership has a gas supply agreement with Engage Energy Canada, L.P.
("Engage") to provide the Partnership with 12,850 mmbtu per day of firm gas. The
gas supply agreement with Engage will terminate on October 31, 1998.
The Partnership and ENCO have a gas management agreement with Engage. The
gas management agreement was assigned to Engage by Westcoast Gas Services, Inc.
during 1997. Engage is paid a gas management fee for each mmbtu of gas delivered
to the Generation Facility. The gas management fee is adjusted annually based on
the British Columbia Consumer Price Index. The gas management agreement expires
October 31, 2008 unless terminated earlier as provided for in the agreement.
As collateral for the obligations of the Company under the gas supply and
gas management agreements with Engage, the Partnership has in place an
irrevocable standby letter of credit with Credit Suisse in favor of Engage. As
of December 31, 1997 and 1996, the letter of credit had a face amount of
$500,000.
ENCO is committed to the utilization of gathering, processing and pipeline
capacity on the Westcoast Energy Inc. ("WEI") system. These firm capacity
commitments are under contracts of varying lengths. Firm capacity has been
accepted at an annual cost of approximately $3,553,000 in 1997, $3,526,000 in
1996 and $2,569,000 in 1995.
Future minimum capacity commitments at December 31, 1997 are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
------------ -----------
<S> <C>
1998............................ $ 2,848,000
1999............................ 5,619,000
2000............................ 2,939,000
2001............................ 2,978,000
2002............................ 2,939,000
Thereafter...................... 11,048,000
-----------
Total................. $28,371,000
===========
</TABLE>
F-64
<PAGE> 119
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
As collateral for the obligations of ENCO under the capacity contracts with
WEI, the Partnership has in place an irrevocable standby letter of credit with
Credit Suisse in favor of WEI. As of December 31, 1997 and 1996, the letter of
credit had a face amount of approximately $384,000 (Canadian).
Utility services -- The Partnership has an agreement for utility services
with the City of Sumas, Washington. The City of Sumas has agreed to provide a
guaranteed supply of water at its wholesale rate charged to external association
customers. Should the Partnership fail to purchase the daily average minimum of
550 gallons per minute from the City of Sumas during the first 10 years of
commercial operation, except for uncontrollable forces or reasonable and
necessary shutdowns, the Partnership shall make up the lost revenue to the City
of Sumas in accordance with the agreement.
During 1997, the Partnership obtained a $700,000 letter of credit in favor
of the City of Sumas to support a future sewer charge which will be payable to
the City of Sumas. The City of Sumas is undertaking a sewer expansion project
which will allow the Generation Facility to discharge its cooling tower blowdown
water into the City's sewer system. The sewer expansion is expected to be
completed in late 1998. When sewer service commences, the Partnership will be
obligated to pay a water discharge capacity payment of approximately $12,000 per
month.
The Partnership has an agreement for waste water disposal with the City of
Bellingham, Washington. The City of Bellingham has agreed to accept up to 70,000
gallons of waste water daily at a rate of one cent per gallon. The agreement
expires on December 31, 1998.
The Partnership has a permit for waste water disposal from the Washington
State Department of Ecology which expires June 30, 2000.
Lease commitments -- In December 1990, the Partnership entered into a
23.5-year land lease which may be renewed for five consecutive five-year
periods. Rental expense was approximately $55,600 in 1997, $56,600 in 1996 and
$48,400 in 1995.
In 1997, ENCO signed an operating lease for office space which expires in
March 2001. Monthly rental expense is approximately $1,846. Rental expense was
approximately $19,000 in 1997, $20,400 in 1996 and $17,700 in 1995.
Future minimum land and office lease commitments as of December 31, 1997
are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
------------ ----------
<S> <C>
1998.................................. $ 71,500
1999.................................. 71,500
2000.................................. 74,700
2001.................................. 61,300
2002.................................. 55,700
Thereafter............................ 756,800
----------
Total....................... $1,091,500
==========
</TABLE>
Affiliate loan -- In 1994, the sole shareholder of SEI obtained a loan from
Calpine in the amount of $10,000,000. During 1997, Calpine assigned the loan to
a third party. The sole shareholder of SEI entered into an amended and restated
loan agreement with the new lender.
Affiliate revolving line of credit -- In 1997, the sole shareholder of SEI
entered into a Revolving Loan Agreement with Calpine. The loan agreement
provides for Calpine to loan up to $15,000,000 to the SEI shareholder. Loans
bear interest at LIBOR plus 3.5% and are due in full on December 31, 2003. As of
December 31, 1997, no borrowings had been made under the loan.
F-65
<PAGE> 120
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
7. FAIR VALUES OF FINANCIAL INSTRUMENTS
The carrying amount of all cash and cash equivalents, accounts receivable
and accounts payable reported in the consolidated balance sheet is estimated by
the Company to approximate their fair value.
The Company is not able to estimate the fair value of its debt with a
carrying amount of $133,400,004 and $117,000,003 at December 31, 1997 and 1996,
respectively. There is no ability to assess current market interest rates of
similar borrowing arrangements for similar projects because the terms of each
such financing arrangement is the result of substantial negotiations among
several parties.
F-66
<PAGE> 121
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
------- ------------------------------------------------------------
<S> <C> <C>
3.1 -- Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(l)
3.2 -- Amended and Restated Bylaws of Calpine Corporation, a
Delaware corporation.(l)
4.1 -- Indenture dated as of February 17, 1994 between the Company
and Shawmut Bank of Connecticut, National Association, as
Trustee, including form of Notes.(a)
4.2 -- Indenture dated as of May 16, 1996 between the Company and
Fleet National Bank, as Trustee, including form of Notes.(m)
10.1 -- Financing Agreements
10.1.1 -- Term and Working Capital Loan Agreement, dated as of June 1,
1990, between Calpine Geysers Company, L.P. (formerly Santa
Rosa Geothermal Company, L.P.) and Deutsche Bank AG, New
York Branch.(a)
10.1.2 -- First Amendment to Term and Working Capital Loan Agreement,
dated as of June 29, 1990, between Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.) and
Deutsche Bank AG, New York Branch.(a)
10.1.3 -- Second Amendment to Term and Working Capital Loan Agreement,
dated as of December 1, 1990, between Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.)
and Deutsche Bank AG, New York Branch.(a)
10.1.4 -- Third Amendment to Term and Working Capital Loan Agreement,
dated as of June 26, 1992, between Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.),
Deutsche Bank AG, New York Branch, National Westminster Bank
PLC, Union Bank of Switzerland, New York Branch, and The
Prudential Insurance Company of America.(a)
10.1.5 -- Fourth Amendment to Term and Working Capital Loan Agreement,
dated as of April 1, 1993, between Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.),
Deutsche Bank AG, New York Branch, National Westminster Bank
PLC, Union Bank of Switzerland, New York Branch, and The
Prudential Insurance Company of America.(a)
10.1.6 -- Construction and Term Loan Agreement, dated as of January
30, 1992, between Sumas Cogeneration Company, L.P., The
Prudential Insurance Company of America and Credit Suisse,
New York Branch.(a)
10.1.7 -- Amendment No. 1 to Construction and Term Loan Agreement,
dated as of May 24, 1993, between Sumas Cogeneration
Company, L.P., The Prudential Insurance Company of America
and Credit Suisse, New York Branch.(a)
10.1.8 -- Credit Agreement Construction Loan and Term Loan Facility,
dated as of January 10, 1990, between Credit Suisse and
O.L.S. Energy-Agnews.(a)
10.1.9 -- Amendment No. 1 to Credit Agreement Construction Loan and
Term Loan Facility, dated as of December 5, 1990, between
Credit Suisse and O.L.S. Energy-Agnews.(a)
10.1.10 -- Participation Agreement, dated as of December 1, 1990,
between O.L.S. Energy-Agnews, Nynex Credit Company, Credit
Suisse, Meridian Trust Company of California and GATX
Capital Corporation.(a)
10.1.11 -- Facility Lease Agreement, dated as of December 1, 1990,
between Meridian Trust Company of California and O.L.S.
Energy-Agnews.(a)
10.1.12 -- Project Revenues Agreement, dated as of December 1, 1990,
between O.L.S. Energy-Agnews, Meridian Trust Company of
California and Credit Suisse.(a)
10.1.13 -- Project Credit Agreement, dated as of June 30, 1995, between
Calpine Greenleaf Corporation, Greenleaf Unit One
Associates, Greenleaf Unit Two Associates, Inc. and The
Sumitomo Bank, Limited.(g)
10.1.14 -- Lease dated as of April 24, 1996 between BAF Energy A
California Limited Partnership, Lessor, and Calpine King
City Cogen, LLC, Lessee.(j)
</TABLE>
<PAGE> 122
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
------- ------------------------------------------------------------
<S> <C> <C>
10.1.15 -- Credit Agreement, dated as of August 28, 1996, among Calpine
Gilroy Cogen, L.P. and Banque Nationale de Paris.(l)
10.1.16 -- Credit Agreement, dated as of September 25, 1996, among
Calpine Corporation and The Bank of Nova Scotia.(m)
10.1.17 -- Credit Agreement, dated December 20, 1996, among Pasadena
Cogeneration L.P. and ING (U.S.) Capital Corporation and The
Bank Parties Hereto.(n)
10.2 -- Purchase Agreements
10.2.1 -- Purchase Agreement, dated as of April 1, 1993, between
Sonoma Geothermal Partners, L.P., Healdsburg Energy Company,
L.P. and Freeport-McMoRan Resource Partners, Limited
Partnership.(a)
10.2.2 -- Stock Purchase Agreement, dated as of June 27, 1994, between
Maxus International Energy Company, Natomas Energy Company,
Calpine Corporation and Calpine Thermal Power, Inc., and
amendment thereto dated July 28, 1994.(b)
10.2.3 -- Share Purchase Agreement dated March 30, 1995 between
Calpine Corporation, Calpine Greenleaf Corporation, Radnor
Power Corp. and LFC Financial Corp.(e)
10.2.4 -- Asset Purchase Agreement, dated as of August 28, 1996, among
Gilroy Energy Company, McCormick & Company, Incorporated and
Calpine Gilroy Cogen, L.P.(m)
10.2.5 -- Noncompetition/Earnings Contingency Agreement, dated as of
August 28, 1996, among Gilroy Energy Company, McCormick &
Company, Incorporated and Calpine Gilroy Cogen, L.P.(m)
10.3 -- Power Sales Agreements
10.3.1 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the Bear Canyon Facility, dated November 30,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), Amendment dated October 17, 1985, Second Amendment
dated October 19, 1988, and related documents.(a)
10.3.2 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the Bear Canyon Facility, dated November 29,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), and Modification dated November 29, 1984, Amendment
dated October 17, 1985, Second Amendment dated October 19,
1988, and related documents.(a)
10.3.3 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the West Ford Flat Facility, dated November 13,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), and Amendments dated May 18, 1987, June 22, 1987,
July 3, 1987 and January 21, 1988, and related documents.(a)
10.3.4 -- Agreement for Firm Power Purchase, dated as of February 24,
1989, between Puget Sound Power & Light Company and Sumas
Energy, Inc. and Amendment thereto dated September 30,
1991.(a)
10.3.5 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated April 16, 1985, between O.L.S. Energy-Agnews and
Pacific Gas & Electric Company and amendment thereto dated
February 24, 1989.(a)
10.3.6 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated November 15, 1984, between Geothermal Energy Partners,
Ltd. and Pacific Gas & Electric Company, and related
documents.(a)
10.3.7 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated November 15, 1984, between Geothermal Energy Partners,
Ltd. and Pacific Gas & Electric Company (see Exhibit 10.3.6
for related documents).(a)
10.3.8 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated December 12, 1984, between Greenleaf Unit One
Associates, Inc. and Pacific Gas and Electric Company.(f)
</TABLE>
<PAGE> 123
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
------- ------------------------------------------------------------
<S> <C> <C>
10.3.9 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated December 12, 1984, between Greenleaf Unit Two
Associates, Inc. and Pacific Gas and Electric Company.(f)
10.3.10 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated December 5, 1985, between Calpine Gilroy Cogen, L.P.
and Pacific Gas and Electric Company, and Amendments thereto
dated December 19, 1993, July 18, 1985, June 9, 1986, August
18, 1988 and June 9, 1991.(l)
10.3.11 -- Amended and Restated Energy Sales Agreement, dated December
16, 1996, between Phillips Petroleum Company and Pasadena
Cogeneration, L.P.(n)
10.4 -- Steam Sales Agreements
10.4.1 -- Geothermal Steam Sales Agreement, dated July 19, 1979,
between Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.), and Sacramento Municipal Utility
District, and related documents.(a)
10.4.2 -- Agreement for the Sale and Purchase of Geothermal Steam,
dated March 23, 1973, between Calpine Geysers Company, L.P.
(formerly Santa Rosa Geothermal Company, L.P.) and Pacific
Gas & Electric Company, and related letter dated May 18,
1987.(a)
10.4.3 -- Thermal Energy and Kiln Lease Agreement, dated as of January
16, 1992, between Sumas Cogeneration Company, L.P. and
Socco, Inc., and Amendment thereto dated May 24, 1993.(a)
10.4.4 -- Amended and Restated Energy Service Agreement, dated as of
December 1, 1990, between the State of California and O.L.S.
Energy-Agnews.(a)
10.4.5 -- Agreement for the Sale of Geothermal Steam, dated as of July
28, 1992, between Thermal Power Company and Pacific Gas &
Electric Company.(c)
10.4.6 -- Amendment to the Agreement for the Sale of Geothermal Steam,
dated as of August 9, 1995, between Union Oil Company of
California, NEC Acquisition Company, Thermal Power Company,
and Pacific Gas and Electric Company.(h)
10.5 -- Service Agreements
10.5.1 -- Operation and Maintenance Agreement, dated as of April 5,
1990, between Calpine Operating Plant Services, Inc.
(formerly Calpine-Geysers Plant Services, Inc.) and Calpine
Geysers Company, L.P. (formerly Santa Rosa Geothermal
Company, L.P.).(a)
10.5.2 -- Amended and Restated Operating and Maintenance Agreement,
dated as of January 24, 1992, between Calpine Operating
Plant Services, Inc. and Sumas Cogeneration Company, L.P.(a)
10.5.3 -- Amended and Restated Operation and Maintenance Agreement,
dated as of December 31, 1990, between O.L.S. Energy-Agnews
and Calpine Operating Plant Services, Inc. (formerly Calpine
Cogen-Agnews, Inc.).(a)
10.5.4 -- Operating and Maintenance Agreement, dated as of January 1,
1995, between Calpine Corporation and Geothermal Energy
Partners, Ltd.(h)
10.5.5 -- Amended and Restated Operating Agreement for the Geysers,
dated as of December 31, 1993, by and between Magma-Thermal
Power Project, a joint venture composed of NEC Acquisition
Company and Thermal Power Company, and Union Oil Company of
California.(c)
10.6 -- Gas Supply Agreements
10.6.1 -- Gas Sale and Purchase Agreement, dated as of December 23,
1991, between ENCO Gas, Ltd. and Sumas Cogeneration Company,
L.P.(a)
10.6.2 -- Gas Management Agreement, dated as of December 23, 1991,
between Canadian Hydrocarbons Marketing Inc., ENCO Gas, Ltd.
and Sumas Cogeneration Company, L.P.(a)
10.6.4 -- Natural Gas Sales Agreement, dated as of November 1, 1993,
between O.L.S. Energy-Agnews, Inc. and Amoco Energy Trading
Corporation.(a)
</TABLE>
<PAGE> 124
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
------- ------------------------------------------------------------
<S> <C> <C>
10.6.5 -- Natural Gas Service Agreement, dated November 1, 1993,
between Pacific Gas & Electric Company and O.L.S.
Energy-Agnews, Inc.(a)
10.7 -- Agreements Regarding Real Property
10.7.1 -- Office Lease, dated March 15, 1991, between 50 West San
Fernando Associates, L.P. and Calpine Corporation.(a)
10.7.2 -- First Amendment to Office Lease, dated April 30, 1992,
between 50 West San Fernando Associates, L.P. and Calpine
Corporation.(a)
10.7.3 -- Geothermal Resources Lease CA 1862, dated July 25, 1974,
between the United States Bureau of Land Management and
Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.).(a)
10.7.4 -- Geothermal Resources Lease PRC 5206.2, dated December 14,
1976, between the State of California and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.).(a)
10.7.5 -- First Amendment to Geothermal Resources Lease PRC 5206.2,
dated April 20,1994, between the State of California and
Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.).(a)
10.7.6 -- Industrial Park Lease Agreement, dated December 18, 1990,
between Port of Bellingham and Sumas Energy, Inc.(a)
10.7.7 -- First Amendment to Industrial Park Lease Agreement, dated as
of July 16, 1991, between Port of Bellingham, Sumas Energy,
Inc., and Sumas Cogeneration Company, L.P.(a)
10.7.8 -- Second Amendment to Industrial Park Lease Agreement, dated
as of December 17, 1991, between Port of Bellingham and
Sumas Cogeneration Company, L.P.(a)
10.7.9 -- Amended and Restated Cogeneration Lease, dated as of
December 1, 1990, between the State of California and O.L.S.
Energy-Agnews.(a)
10.8 -- General
10.8.1 -- Limited Partnership Agreement of Sumas Cogeneration Company,
L.P., dated as of August 28, 1991, between Sumas Energy,
Inc. and Whatcom Cogeneration Partners, L.P.(a)
10.8.2 -- First Amendment to Limited Partnership Agreement of Sumas
Cogeneration Company, L.P., dated as of January 30, 1992,
between Whatcom Cogeneration Partners, L.P. and Sumas
Energy, Inc.(a)
10.8.3 -- Second Amendment to Limited Partnership Agreement of Sumas
Cogeneration Company, L.P., dated as of May 24, 1993,
between Whatcom Cogeneration Partners, L.P. and Sumas
Energy, Inc.(a)
10.8.4 -- Second Amended and Restated Shareholders' Agreement, dated
as of October 22, 1993, among GATX Capital Corporation,
Calpine Agnews, Inc., JGS-Agnews, Inc., and
GATX/Calpine-Agnews, Inc.(a)
10.8.5 -- Amended and Restated Reimbursement Agreement, dated October
22, 1993, between GATX Capital Corporation, Calpine Agnews,
Inc., JGS-Agnews, Inc., GATX/Calpine Agnews, Inc., and
O.L.S. Energy-Agnews, Inc.(a)
10.8.6 -- Amended and Restated Limited Partnership Agreement of
Geothermal Energy Partners Ltd., L.P., dated as of May 19,
1989, between Western Geothermal Company, L.P., Sonoma
Geothermal Company, L.P., and Cloverdale Geothermal
Partners, L.P.(a)
10.8.7 -- Assignment and Security Agreement, dated as of January 10,
1990, between O.L.S.Energy-Agnews and Credit Suisse.(a)
10.8.8 -- Pledge Agreement, dated as of January 10, 1990, between
GATX/Calpine-Agnews, Inc., and Credit Suisse.(a)
10.8.9 -- Equity Support Agreement, dated as of January 10, 1990,
between Calpine Corporation and Credit Suisse.(a)
</TABLE>
<PAGE> 125
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
------- ------------------------------------------------------------
<S> <C> <C>
10.8.10 -- Assignment and Security Agreement, dated as of December 1,
1990, between O.L.S. Energy-Agnews and Meridian Trust
Company of California.(a)
10.8.11 -- First Amended and Restated Limited Partner Pledge and
Security Agreement, dated as of April 1, 1993, between
Sonoma Geothermal Partners, L.P., Healdsburg Energy Company,
L.P., Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.), Freeport-McMoRan Resource
Partners, L.P., and Meridian Trust Company of California.(a)
10.8.12 -- Management Services Agreement, dated January 1, 1995,
between Calpine Corporation and Electrowatt Ltd.(k)
10.8.13 -- Guarantee Fee Agreement, dated January 1, 1995, between
Calpine Corporation and Electrowatt Ltd.(g)
10.9.1 -- Calpine Corporation Stock Option Program and forms of
agreements thereunder.(a)
10.9.2 -- Calpine Corporation 1996 Stock Incentive Plan and forms of
agreements thereunder.(l)
10.9.3 -- Calpine Corporation Employee Stock Purchase Plan and forms
of agreements thereunder.(l)
10.10.1 -- Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright.(l)
10.10.2 -- Senior Vice President Employment Agreement between Calpine
Corporation and Ms. Ann B. Curtis.(l)
10.10.3 -- Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Lynn A. Kerby.(l)
10.10.4 -- Vice President Employment Agreement between Calpine
Corporation and Mr. Ron A.Walter.(l)
10.10.5 -- Vice President Employment Agreement between Calpine
Corporation and Mr. Robert D.Kelly.(l)
10.10.6 -- First Amended and Restated Consulting Contract between
Calpine Corporation and Mr. George J. Stathakis.(l)
10.11 -- Form of Indemnification Agreement for directors and
officers. (l)
10.11.1 -- Amendment to the Steam and Electricity Service Agreement
between Cogenron Inc. and Union Carbide Corporation dated
June 12, 1985.*
10.11.2 -- Ground Lease Agreement, between Union Carbide Corporation
and Northern Cogneration One Company dated January 1, 1986
in Texas City, Texas.*
10.11.3 -- Stock Purchase Agreement Among Gas Energy Inc., Gas Energy
Cogeneration Inc. Calpine Eastern Corporation and Calpine
Corporation dated August 22, 1997.*
10.11.4 -- First Amendment to the Stock Purchase Agreement Among Gas
Energy, Inc., Gas Cogernation Inc., The Brooklyn Union Gas
Company and Calpine Eastern Corporation and Calpine
Corporation dated August 22, 1997; as amended on December
19, 1997.*
10.11.5 -- Amended and Restated Congenerated Electricity Sale and
Purchase Agreement by and between Cogenron Inc., and Texas
Utilities Electric Company dated June 12, 1985; as
previously amended, and as amended and restated on December
29, 1997.*
10.11.6 -- Agreement for the Purchase of Electrical Power and Energy
between Capital Congernation Company, Ltd. and Texas-New
Mexico Power Company Power Agreement.*
21.1 -- Subsidiaries of the Company.(m)
27.0 -- Financial Data Schedule.*
</TABLE>
- ---------------
(a) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 33-73160).
<PAGE> 126
(b) Incorporated by reference to Registrant's Current Report on Form 8-K dated
September 9, 1994 and filed on September 26, 1994.
(c) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated September 30, 1994 and filed on November 14, 1994.
(d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1994 and filed on March 29, 1995.
(e) Incorporated by reference to Registrant's Current Report on Form 8-K dated
April 21, 1995 and filed on May 5, 1995.
(f) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1995 and filed on May 12, 1995.
(g) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1995 and filed on August 14, 1995.
(h) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated September 30, 1995 and filed on November 14, 1995.
(i) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1995 and filed on March 29, 1996.
(j) Incorporated by reference to Registrant's Current Report on Form 8-K dated
May 1, 1996 and filed on May 14, 1996.
(k) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1996 and filed on May 15, 1996.
(l) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 333-07497).
(m) Incorporated by reference to Registrant's Current Report on Form 8-K dated
August 29, 1996 and filed on September 13, 1996.
(n) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1996, filed on March 27, 1996.
* Filed herewith.
<PAGE> 1
EXHIBIT 10.11.1
This June 27, 1997 amendment ("Amendment") to the Steam and Electricity Service
Agreement between Cogenron Inc. (successor in interest to Northern Cogeneration
One Company) ("Company") and Union Carbide Corporation ("Customer") dated June
12, 1985, as amended ("Agreement") is effective the 31st day of December, 1996.
WHEREAS, Company and Customer desire to amend the Agreement;
NOW, THEREFORE, Company and Customer agree that the Agreement hereby
amended as follows:
1.
The following Articles related to the Secondary Steam Discount are
hereby Amended as follows:
1. Article 1.31 is hereby amended by (1) adding a new sentence between the
first and second sentences thereof which reads "Wheeling Costs shall be defined
as $12,600,000,00 for 1997, and escalated at 2% per year thereafter.", and (2)
adding the following language at the end of this Article "Company shall refund
to Customer 50% of the Maintenance Reserve balance as of June 30, 1999. In
computing this refund, the Maintenance Reserve balance shall be reduced by the
amount by which Company estimates payments will exceed accruals for the period
from July 1, 1999 through December 31, 1999, if applicable. After December 31,
1999, Company shall adjust the amount of the June 30, 1999 refund for any
variance between actual payments in excess of accruals between July 1, 1999 and
December 31, 1999 and the estimates used to calculate the June 30, 1999 refund.
2. Article 1.36 is hereby amended to read as follows:
1.36 PROJECT REVENUES: Base steam revenues at Ceiling Base Steam Price
plus revenues from Supplemental Steam and Incentive Steam, to Customer
and electric power/energy to Purchasing Utility. In determining revenues
from electric power/energy sales to a Purchasing Utility, the value used
for capacity revenue from such a Purchasing Utility shall be the Actual
Capacity Volume multiplied by twenty dollars and fifteen cents per
kilowatt/month ($20.15/Kw/Mo.) for 1997, twenty dollars and forty-two
cents per kilowatt/month ($20.42/Kw/Mo.) for 1998, and twenty-two
dollars and nineteen cents per kilowatt/month ($22.19/Kw/Mo.) for the
period from January 1, 1999 through June 30, 1999. Actual Capacity
Volume shall mean the Contract Level or Contract Capacity (410 MW) as
defined by the Cogenerated Electricity Sale and Purchase Agreement
between Enron Cogeneration One Company (formerly Northern Cogeneration
One Company) and Texas Utilities Electric Company, dated June 12, 1985,
as amended (the "PPA") less any adjustments made pursuant to such
Contract Level or Capacity with respect to certain minimum Capacity
Factor Performance Levels and performance tests as specified in the PPA.
2.
The following Articles related to the sale of electricity to Customer
are hereby deleted in their entirety:
<PAGE> 2
Article 2.2, including Articles 2.2.1 through and including 2.2.4;
Article 4.2, including Articles 4.2.1 through and including 4.2.3;
Article 5.2, including Articles 5.2.1 through and including 5.2.2;
Article 8.1.6; and Article 9.6.
3.
1. The following Articles related to the sale of electricity to Customer
are hereby amended as follows:
1. The second "WHEREAS" clause is hereby amended by dele phrase
"and electric service" therefrom.
2. The third "WHEREAS" clause is hereby amended by deleting the
"and electricity" therefrom.
3. Article 1.40 is hereby amended by deleting the phrase
"electricity" therefrom.
4. Article 2.0 is hereby amended by deleting the phrase "and
electric" from the first sentence thereof.
5. Article 2.3 is hereby amended to read as follows:
"2.3 Company shall not, without the prior written consent of
Customer, curtail or reduce steam availability to Customer below
six hundred thousand pounds per hour (600 Mlbs/hr) for the
purpose of increasing or maintaining electrical power/energy
sales to the Purchasing Utility. If such reductions or
curtailments are made without the consent of Customer, then
Company shall compensate Customer for the incremental cost or
penalties of producing or purchasing an equivalent amount of
said Service over what Customer would have paid Company for said
Service."
6. Article 2.5.3 is hereby amended by deleting therefrom the phrase
"and/or electrical energy".
<PAGE> 3
7. Article 2.5.4 is hereby amended by deleting therefrom the phrase
"and/or electric energy".
8. Article 4.1.3 is hereby amended by deleting the phrase "or
Customer" from the first sentence thereof.
9. Article 4.3 is hereby amended by amending the second sentence to
read as follows:
"For the purposes of an exchange of gas pursuant to Section
2.5.3, (i) Gas shall be deemed to have a value equal to the
Cogeneration Fuel Cost in effect at the time of actual delivery,
and (ii) the value of the steam shall be determined pursuant to
the provisions of Section 4.1 as though no exchange had
occurred."
10. Article 6.0 is hereby amended by deleting the phrase "and
electricity" from the second and fourth sentences thereof and by
deleting the phrase ", electricity" from the sixth and seventh sentences
thereof.
11. Article 8.1 is hereby amended by changing the caption to read
"Steam Metering."
12. Article 8.1.1 is hereby amended by deleting the phrase "and
electricity" therefrom.
13. Article 12.2(d) is hereby amended by deleting the phrase "and
electricity" from the last sentence thereof.
14. Article 12.2(e) is hereby amended by deleting the phrase "and
electric power" therefrom.
15. Article 13.0 is hereby amended by deleting the phrase "and
electricity" from the first and second sentences of the first paragraph
thereof.
<PAGE> 4
It is the intention of the Parties to amend the Agreement insofar and
only insofar as stated in the amendments contained herein and, subject to the
foregoing paragraphs, the Parties hereby affirm all other terms of the
Agreement.
IN WITNESS HEREOF, Company and Customer hereby execute this Amendment as
of the date first above written.
Company
COGENRON INC.
By:______________________________________
Title:
ATTEST:
By:_______________________________
Title:
Customer
UNION CARBIDE CORPORATION
By:______________________________________
Title:
ATTEST:
By:_______________________________
Title:
<PAGE> 5
AMENDMENT TO THE
STEAM AND ELECTRICITY AGREEMENT
BETWEEN
COGENRON INC. & UNION CARBIDE CORPORATION
DATED JUNE 12,1985
This August 19, 1997 amendment ("Amendment") to the Steam &
Electricity Service Agreement between Cogenron Inc. (successor in interest to
Northern Cogeneration One Company) ("Company") and Union Carbide Corporation
("Customer"), dated June 12, 1985, as amended ('Agreement' & is effective the
31st day of December, 1996.
WHEREAS, Company and Customer desire to amend the Agreement.
WHEREAS, Company and Customer entered into a June 27, 1997 amendment
to the Agreement. Company and Customer agree that the June 27, 1997 amendment
inadvertently deleted Article 4.2, Cost of Electric Service, from the Agreement.
It was not the Patties intention to delete Article 4.2 from the Agreement. The
purpose of this Amendment is, therefore, to reinstate Article 4.2 into the
Agreement and modify it as more fully described below.
NOW, THEREFORE, Company and Customer agree that the Agreement is
hereby amended as follows:
16. Article 4.2.1 is hereby amended to read as follows:
The monthly charge for electric Service shall consist of a
capacity charge.
17. Article 4.2.2 is hereby amended to read as follows:
The monthly capacity charge shall be determined by
multiplying the demand quantity of 20,000 kilowatts by the appropriate
rate hereunder:
CALENDAR $/KW - Month
YEAR
1997 8.447
1998 8.954
1999 9.492
18. Article 4.2.3 is deleted in its entirety.
It is the intention of the Parties to amend the Agreement insofar and
only insofar as stated in the amendments contained herein and, subject to the
foregoing paragraphs, the Parties hereby affirm all other terms of the
Agreement.
IN WITNESS HEREOF, Company and Customer hereby execute this Amendment
as of the date first above written.
Company
COGENRON INC.
<PAGE> 6
By:______________________________________
Title:
ATTEST:
By:_______________________________
Title:
Customer
UNION CARBIDE CORPORATION
By:______________________________________
Title:
ATTEST:
By:_______________________________
Title:
<PAGE> 7
STEAM AGREEMENT &
BETWEEN
COGENRON INC.
AND
UNION CARBIDE CORPORATION
JULY 1, 1997
<PAGE> 8
STEAM AGREEMENT
This Steam Agreement ("Agreement") is entered into as of the 1st day of July,
1997 by and between Cogenron Inc. ("Cogenron" or "Company") and Union Carbide
Corporation ("UCC" or "Customer").
WITNESSETH:
WHEREAS, Cogenron is a Delaware corporation and a wholly owned
subsidiary of Enron Cogeneration; Enron Cogeneration is a Delaware corporation
and a wholly owned subsidiary of Texas Cogeneration Company; and Texas
Cogeneration Company is a Delaware corporation, which is owned 50 percent by
Dominion Energy, Inc. and 50 percent by Calpine Corporation.
WHEREAS, Cogenron will operate and maintain facilities for the
purposes of producing steam near UCC's plant in Texas City, Texas; and
WHEREAS, UCC is the owner of a plant located in Texas City, Texas, and
desires to purchase steam from Cogenron; and
WHEREAS, Cogenron is willing to sell or exchange steam to UCC under
the terms and conditions set forth herein.
Article 1 - Definitions
1.1 UCC Land: The land owned by UCC adjacent to Cogenron's land in Texas
City, Texas, and which is described in Appendix I attached hereto,
except that Cogenron's land is expressly excluded from such
definition.
1.2 UCC's Plant: The plant, including equipment, rolling stock and all
personal property of any kind, owned and operated by, or with the
agreement of, UCC on UCC's land, being the property and equipment on
UCC's land side of the Point of Delivery, excluding the Retrofit
Equipment.
1.3 Cogenron's Land: The land leased by Cogenron adjacent to UCC's land in
Texas City, Texas, and which is described by metes and bounds in
Appendix I attached hereto.
1.4 Cogenron's Plant: The plant, including equipment, rolling stock and
all personal property of any kind, owned and operated by Cogenron on
Cogenron's land, being the property and equipment on Cogenron's land
side of the Point of Delivery up to and including the Point of
Delivery.
1.5 Retrofit Equipment: That equipment as set forth in Appendix 2 attached
owned, constructed and provided by Cogenron on UCC's land.
1.6 Gas Service: Gas that UCC elects to supply under the provisions of
Articles 4.3.2
Article 2 - Term
<PAGE> 9
2.1 This contract shall be in effect from July 1, 1999 until October 19,
2003. The contract term shall be automatically extended past October
19, 2003 until notice of termination is given by either party at least
twenty-four (24) months before the desired termination date. A notice
of termination must be in writing.
Article 3 - Service to be Provided by Cogenron
3.1 Upon request by UCC Cogenron will furnish UCC with 300,000 lbs/hour of
steam on a monthly average basis. Nevertheless, at no point shall
Cogenron be required to deliver more than 600,000 lbs/hour on an
instantaneous basis.
3.2 Cogenron will also provide UCC with an additional 300,000 lbs/hour of
steam for up to seven (7) times per year not to exceed a cumulative
total of eight hundred forty (840) hours in any calendar year. This
right as provided by this Article 3.2 to additional steam is
hereinafter referred to as a "Call Option." This Call Option is
intended to provide UCC with incremental steam quantities necessitated
by performance of maintenance at customer's facility and shall be
declared in advance of the event. For the period from July 1, 1999
through December 31, 1999, the Call Option may be exercised for up to
four (4) times not to exceed a cumulative total of four hundred
thirty-two (432) hours. For the period from January 1, 2003 through
October 19, 2003, the Call Option may be exercised for up to six (6)
times not to exceed a cumulative total of seven hundred twenty (720)
hours. If this Agreement has not been terminated by October 19, 2003
for the period from October 20, 2003 through the termination date of
the contract, the Call Option may be exercised on a pro rata basis
(rounded down) for up to seven (7) times per twelve (12) month period
not to exceed a cumulative total of 840 hours per twelve (12) month
period.
3.3 The quantities of steam described in articles 3.1 and 3.2 shall be
referred to as "Base Stearn Quantities."
3.4 Upon request by UCC Cogenron shall, if available, furnish UCC
incremental "Supplemental Steam Quantities" in excess of the Base
Stearn Quantities. It is within Cogenron's discretion as to whether
Supplemental Stearn Quantities are available.
3.5 During UCC's plant normal operation, UCC's designated employee shall
verbally notify Cogenron once at the beginning of each twelve (12)
hour work shift, or as otherwise mutually agreed, of the quantity of
steam Customer anticipates taking from Cogenron during said work
shift.
3.6 At the beginning of each calendar month, UCC shall provide Cogenron
with its reasonable best estimate of projected Call Option dates for
the succeeding twelve (12) months.
Article 4 - Price
4.1 Each month, UCC shall pay Cogenron (1) a Facilities Charge; and (2) a
Monthly Steam Charge. The Monthly Steam Charge, based on steam
deliveries, is comprised of a monthly charge for Base Stearn
Quantities and a monthly charge for Supplemental Stearn Quantities.
4.2 The Facilities Charge is & 100,000 per month.
<PAGE> 10
4.3 The monthly charge for Base Steam Quantities is comprised of a Fuel
Component and an Operations and Maintenance Component.
4.3.1 The Fuel Component is calculated by multiplying Cogenron's total
weighted average cost of gas ("Cogen Fuel Cost") for the applicable
month by a fixed "Equivalent Boiler Rate" of 1.2760 mBtu/lb. Cogen
Fuel Cost, expressed in $/mmBtu, shall be computed as the total
commodity cost of gas consumed by Cogenron's Texas City facilities
during the month, including any demand and scheduling or reservation
charges, divided by the total quantity of fuel consumed during the
applicable month. The Fuel Component will be adjusted monthly.
4.3.2 Cogenron shall present to UCC any proposed gas supply arrangement(s)
required to produce requested steam quantities under this Agreement.
Cogenron cannot enter into such a gas supply arrangement(s) until
written approval is given by UCC In the event UCC does not provide
written approval of a proposed gas supply arrangement(s) UCC will
provide the gas quantities necessary to provide the requested steam
quantities under this Agreement. UCC will be required to provide the
gas quantities necessary to produce the requested steam quantities
under this Agreement until such time as UCC directs Cogenron to secure
a third-party gas contract and UCC approves the proposed third-party
gas contract. Cogenron shall not terminate or amend such approved gas
supply arrangement(s) without prior written approval from UCC
4.3.3 Notwithstanding Article 4.3.2, upon delivery of notice by July 1,
1998, UCC may elect to supply such gas quantities necessary to produce
requested steam quantities for the term of this Agreement. Such gas
quantities shall meet the specifications as set forth in Appendix 3.
If UCC elects to provide gas quantities and fails to supply gas
quantities equal to the amount necessary to produce requested steam
quantities (calculated based on the Equivalent Boiler Rate), UCC shall
reimburse Cogenron for the replacement cost of natural gas, including
any imbalance premiums or other charges. Such reimbursement shall be
calculated by Cogenron in accordance with Article 4.6.
4.3.4 The Operations and Maintenance Component is $0.30/mlb of steam.
4.4 The monthly charge for Supplemental Steam Quantities is the monthly
charge for Base Steam- Quantities plus $0.50/mlb.
4.5 For billing purposes, monthly average steam deliveries (adjusted for
steam deliveries associated with the Call Option) will be used to
determine Base Steam Quantities and Supplemental Steam Quantities.
Nevertheless, should UCC request instantaneous steam deliveries in
excess of 600,000 lbs/hour and Cogenron elects to deliver such
requested quantities, such amounts in excess of 600,000 lbs/hour for
each hour shall be billed at the monthly charge for Supplemental
Stearn Quantities.
4.6 The regular billing period shall be the calendar month. All invoices
are due on presentation and payable within twenty (20) days of
receipt. Late payments by UCC shall bear interest at UCC's then
current short-term borrowing rate plus one percent (I%), not to exceed
the maximum interest rate permitted to be charged by applicable law.
<PAGE> 11
Article 5 - Point of Delivery
5.1 All steam under this contract will be delivered at the Point of
Delivery. The Point of Delivery are those points specified in Appendix
4. All right, title, and interest in and to any steam delivered under
this Agreement shall pass from Cogenron to UCC at the Point of
Delivery. Cogenron shall have the risk of loss of all steam to be
delivered under this Agreement up to and at the Point of Delivery. UCC
shall have the risk of loss of all steam delivered under this
Agreement from and after the Point of Delivery. Notwithstanding the
foregoing, if the loss of any steam is due to equipment, materials or
processes or any other matter under the control and maintenance, as
provided herein, of the party other than the one for which risk of
loss has been allocated as provided above, such party shall be liable
for the loss of any such steam. Liability for all damages caused by or
arising out of the steam to be delivered hereunder shall lie with the
party responsible for the risk of loss as specified in this article,
except to the extent the damages are caused by the negligence or
misconduct of the other party.
Article 6 - Article 6 & Services to Be Provided by UCC
6.1 UCC shall, without charge, provide to Cogenron: (1) facilities to
handle storm water runoff; (2) firewater; (3) wastewater treatment up
to an instantaneous flow of 3,000 gallons per minute; and (4) boiler
quality water in sufficient quantities to produce UCC's requested
steam takes, including an additional amount for necessary and
customary blowdown and losses, estimated at 1.5 percent. Such boiler
quality water shall meet the specifications defined in Appendix 5.
Should UCC fail to deliver boiler quality water in accordance with the
specifications detailed in Appendix 5, Cogenron shall make best
efforts to secure boiler quality water from third-party sources, upon
approval by UCC to produce requested steam deliveries. If Cogenron is
unsuccessful in securing boiler quality water from third-party sources
that is in accordance with the specifications detailed in Appendix 5,
Cogenron shall reduce such steam delivery to reflect actual receipt of
boiler quality water that is in accordance with the specifications
detailed in Appendix 5. UCC shall reimburse Cogenron for securing such
boiler quality water.
6.2 UCC shall provide an average of 2,500 gallons per minute and up to a
peak of 3,500 gallons per minute of river water to Cogenron, at UCC's
direct cost.
6.3 UCC shall make reasonable efforts to continue to provide to Cogenron
the services described in 6.1 and 6.2 after termination of this
Agreement at a price to Cogenron that compensates UCC for the direct
cost to provide such services, including a reasonable rate of return
on assets employed by UCC to provide said services.
Article 7 - Ground Lease Agreement
7.1 UCC and Cogenron (successor in interest to Northern Cogeneration One
Company) entered into a Ground Lease Agreement ("Lease"), dated
January 1, 1986. A copy of the Lease is attached as Appendix 7. UCC
and Cogenron agree to extend the Lease, and all rights and obligations
<PAGE> 12
contained therein, for five (5) years beyond the termination of this
Agreement. This includes, but is not limited to, Cogenron's right to
purchase the premises from UCC as set forth in the Lease.
Article 8 - Steam Metering
8.1 Cogenron shall measure the amount of steam delivered hereunder by a
mutually acceptable metering system at the Point of Delivery or at
other mutually acceptable locations as specified in Appendix 4.
8.2 Meters shall be installed, repaired and replaced at Cogenron's
expense. Meters will be tested and calibrated at Cogenron's expense in
accordance with Appendix 6 and with the schedule specified in Article
8.5. UCC may request meter tests at more frequent intervals. If such
requested test determines the meter to be within the accuracy
described herein, UCC will pay all reasonable costs for testing the
meter.
8.3 If at any time, any meter or other equipment constituting an official
meter station is found to be defective, such meter or equipment shall
be readjusted, repaired, or replaced without delay. If, upon any
calibration test, the inaccuracy of the meter or other equipment is
found to affect the measurement of the steam delivered hereunder in
excess of the specified amount when calculating such inaccuracy at the
average flowing conditions experienced during the period following the
previous calibration test, then an equitable adjustment and settlement
in the invoices for prior deliveries shall be promptly made by the
parties on the basis of best data available, using the first of the
following methods which is feasible:
8.3.1 By using the recording of a check meter if available and accurately
recording.
8.3.2 By correcting the error back to zero (0) after the percentage of error
is ascertained by calibration, test, or mathematical calculation for
the period of error, if known; or if unknown for a period extending
back one-half (1/2) of the time since the last calibration; or
8.3.3 If data cannot be obtained from the official or check meters, then
mutually agreeable data from Cogenron and UCC will be used to arrive
at the official meter reading. This data may be in the form of other
meters, production data, or previous and subsequent days' readings.
8.4 Cogenron shall provide notice of any meter test to UCC prior to making
each test of such meter. Such notice may be oral but shall
subsequently be confirmed in writing. UCC shall have the right to have
a representative present at such test to observe the same and any
meter adjustments found thereby to be necessary. UCC may provide at
its own expense (but shall not be obligated to do so) a check meter at
each delivery point and such check meter shall be used for measurement
purposes hereunder, subject to all provisions herein, during any
period when primary meter is inoperable or in such state of disrepair
that accurate measurements cannot be obtained therefrom.
8.5 The steam metering system shall have the capability of measuring the
hourly rat and quantity of steam delivered by Cogenron and received by
UCC and shall be maintained within an accuracy range of plus or minus
<PAGE> 13
one-and-a-half percent. Cogenron at its expense shall test the steam
metering system at least monthly.
Article 9 - Force Majeure
9.1 Neither Cogenron nor UCC shall be liable to the other for failure to
provide or take steam, or to perform any other obligation hereunder,
or for any damages resulting from such failure to the extent that such
failure or damage shall be the result of fire, strike, riot,
explosion, flood, accident, acts of God, the public enemy,
governmental laws, ordinances, rules or regulations (whether valid or
invalid), or without limitation by enumeration, any other acts or
circumstances beyond the reasonable control of either party,
preventing or prohibiting in whole or in part such provision, taking
or performance. Either party's failure to perform its obligations,
either in whole or in part, under the terms of this Agreement to the
extent resulting from a "year 2000 date change event" (i.e., due to
the impact on time and date codes and the affected party's internal
computer programs which impact is associated with the affected party's
operations following December 31, 1999) shall not constitute a Force
Majeure situation and is subject to any remedies that may be available
under this Agreement.
Article 10 - Status of Facility
10.1 UCC shall take delivery and consume sufficient steam quantities to
ensure that Cogenron's plant shall maintain its "Qualifying Facility"
status as defined in 18 CFR (Code of Federal Regulations) 292 as of
the date of the signing of this Agreement. UCC agrees that such steam
shall be thermally used as required by such regulations. In the event
that such rules and regulations governing "Qualifying Facilities"
change, the parties agree to enter into good faith negotiations with
an objective of' reaching a mutually satisfactory arrangement in order
to continue the qualifying status of Cogenron's Plant.
Article 11 - Governing Law
11.1 This Agreement shall be governed by law of the State of Texas.
Article 12 - Assignments
12.1 Except as otherwise provided in this Article, neither party shall
assign this Agreement, or any part thereof, without the prior consent
of the other party and any assignment in violation of this provision
shall be void. This Agreement shall be binding upon and shall inure to
the benefit of the parties and their successors and permitted assigns.
12.2 Either party may assign its rights and obligations under this
Agreement, subject to the prior written approval of the other party
hereto, which approval shall not be unreasonably withheld, to any
subsequent owner of all or substantially all of the assets of UCC's
Plant, the Retrofit Equipment or Cogenron's Plant, as the case may be,
if such subsequent owner accepts the assignment of this Agreement and
assumes the obligations of the conveying party hereunder.
12.3 Either party shall have the right to assign this Agreement to a
subsidiary of affiliate of such party without the consent of the other
<PAGE> 14
party; provided that the assigning party shall not be released from
its obligation hereunder.
Article 13 - Entire Agreement
13.1 This Agreement, together with the attached Appendixes, contain the
entire understanding and Agreement between the parties. This Agreement
may not be amended or modified except by a written instrument,
designated on its face as an "Amendment" to this Agreement, signed by
all parties who have rights under this Agreement.
Article 14 - Confidentiality
14.1 The parties agree that the prices, terms and conditions contained in
this Agreement shall not be disclosed to third parties without the
written consent of all parties.
Article 15 - Steam Service Specifications
15.1 Cogenron shall render steam service to provide an adequate supply to
meet a pressure range of 5 85 psig to 610 psig at the Point of
Delivery and a temperature range of 725' F to 790' F and which meets
the following steam quality requirements: (1) Total Dissolved Solids:
Not more than 0.040 ppm; and (2) Oxygen: Nil.
15.2 Cogenron shall add neutralizing amines such as Nalco 1824 or
equivalent to the feedwater and/or steam to achieve a condensate pH of
8.0 to 9.0.
15.3 Cogenron agrees to provide periodic and as requested steam quality
monitoring records to UCC which may be used to confirm whether the
steam provided to UCC meets the specifications set forth in articles
15.1. and 15.2. Notwithstanding any other provision of this Agreement,
UCC shall not be obligated to accept delivery of steam that does not
meet the specifications of Articles 15.1 and 15.2.
15.4 Except for meeting the specifications contained in articles 15.1 and
15.2, Cogenron does not in any way warrant the fitness of the steam
supplied under this Agreement for the particular purpose for which UCC
intends or may intend to use the steam.
Article 16 - Limitation of Liability
16.1 In no event shall either party be liable to the other hereunder for
incidental, consequential, indirect or special damages, including loss
of profits, arising out of this Contract or its performance of or
failure to perform any obligation hereunder.
Article 17 - Notices
17.1 Any notices or communications permitted or required by this Agreement
shall be deemed properly made if delivered in person or sent by
certified United States Mail, return receipt requested, to the
respective parties at the following addresses:
Cogenron Inc. Union Carbide
Corporation
<PAGE> 15
Attn: President Attn: Mr. C. V. Jensen
Suite 2360 Supply Manager
700 Louisiana 39 Old Ridgebury Road,
Street El
Houston, Texas Danbury, CT 06817-0001
77002
Article 18 - Default of UCC
18.1 The following shall each constitute an Event of Default by UCC under
this Contract:
18.1.1 Failure of UCC to pay in full the charges billed to it by Cogenron for
steam and reimbursement for purchase of boiler quality water as
provided by Article 6.1 received pursuant to this Contract within a
period of ninety (90) days after the date of invoice receipt, unless
UCC shall in good faith be disputing the portion of such invoice that
has not been paid; or
18.1.2 If UCC fails to perform any of the other material provisions of this
Contract or otherwise endangers performance of the Contract in
accordance with its terms; and in either of these two circumstances
does not submit a proposed course of action within a period of thirty
(30) days to correct such failure after receipt of notice from
Cogenron specifying such failure, and thereafter diligently proceeds
to correct such failure; or
18.1.3 The occurrence of any of the following:
18.1.3.1 UCC's bankruptcy or insolvency or the initiation of any proceeding,
voluntary or involuntary, against UCC under the bankruptcy or
insolvency laws, or UCC's failure to meet its debts in the ordinary
course of business; provided, however, that there shall be no Event of
Default if, within thirty (30) days from the written receipt of notice
from Cogenron to terminate for such default, UCC as debtor in
possession or UCC's trustee, receiver, assignee or custodian,
whichever is obligee under this Contract, in writing affirms this
Contract and the Lease and demonstrates to Cogenron' s reasonable
satisfaction the ability to fulfill its or their obligations under
this Contract, and the Lease; or
18.1.3.2 UCC makes an assignment of all or a substantial part of UCC's Plant or
UCC's Land for the benefit of creditors.
18.2 Cogenron may, at its sole option, in the event of an occurrence of an
Event of Default as defined in Section 18. 1, exercise any or all of
the following remedies by written notice of default to UCC which shall
constitute the sole and exclusive remedies available to Cogenron in
connection with this Contract; and provided that Cogenron shall be
required to mitigate any damages that it incurs as a result of such
default, which mitigation obligation shall decrease the amount
otherwise payable by UCC under this Section 18.2:
18.2.1 Cogenron may terminate the whole or any part of this Contract. In the
event of such termination, Cogenron may discontinue steam
<PAGE> 16
deliveries, refuse to receive Gas Service and disconnect and/or remove
the Retrofit Equipment, after reasonable notice to UCC provided entry
on UCC's Land is done in accordance with UCC's safety, security, and
confidentiality requirements.
18.2.2 Cogenron may discontinue steam deliveries and refuse to receive Gas
Service.
18.2.3 Cogenron may disconnect and/or remove the Retrofit Equipment, after
reasonable notice to UCC provided entry on UCC's Land is done in
accordance with UCC's safety and security requirements.
18.3 In the event that UCC cures any such default, Cogenron shall resume
steam deliveries, receive Gas Service and continue its obligations
under this Contract for the duration thereof.
Article 19 - Default of Cogenron
19.1 The following shall each constitute an Event of Default by Cogenron
under this Contract:
19.1.1 Cogenron fails to perform any of the material provisions of this
Contract or otherwise endangers performances of the Contract in
accordance with its terms; and does not submit a proposed course of
action within a period of thirty (30) days to correct such failure
after failure of notice from UCC specifying such failure, and
thereafter diligently proceeds to correct such failure; or
19.1.2 The occurrence of any of the following:
19.1.2.1 Cogenron's bankruptcy or insolvency or the initiation of any
proceeding, voluntary or involuntary, against Cogenron. under the
bankruptcy or insolvency laws, or Cogenron's failure to meet its debts
in the ordinary course of business; provided, however, that there
shall be no Event of Default if, within thirty (30) days from the
written receipt of notice from UCC to terminate for such default,
Cogenron as debtor in possession or Cogenron's trustee, receiver,
assignee or custodian, whichever is obligee under this Contract, in
writing affirms this Contract, the Utility Service Agreement and the
Lease and demonstrates to UCC's reasonable satisfaction the ability to
fulfill its or their obligations under this Contract, the Utility
Service Agreement and the Lease.
19.1.2.2 Cogenron makes an assignment of all or a substantial part of
Cogenron's Plant or Cogenron's Land for the benefit of creditors.
19.2 UCC may, at its sole option, in the event of an occurrence of an Event
of Default as defined in Section 19.1, exercise any or all of the
following remedies by written notice of default to Cogenron, which
shall constitute the sole and exclusive remedies available to UCC in
connection with this Contract; and provided that UCC shall be required
to mitigate any damages that it incurs as a result of such default,
which mitigation obligation shall decrease the amount otherwise
payable by Cogenron under this Section 19.2:
19.2.1 UCC may terminate the whole or any part of this Contract. In the event
of such termination UCC may discontinue Gas Service, refuse to
<PAGE> 17
take steam deliveries and may require title to and possession of the
Retrofit Equipment to be transferred to UCC at no cost to UCC with no
liens or other security interests attached.
19.2.2 UCC may require Cogenron to promptly assign, in whole or in part, its
rights and obligations under each of its gas supply contracts that
provide for the supply of gas to Cogenron's Plant for a portion of Gas
equivalent on a BTU basis to the maximum steam taken provided under
this Contract; provided, however that in the event that the occurrence
of an Event of Default is caused by an insufficient gas supply, then
Cogenron will exert its best efforts to cause assignment of such gas
supply contracts to UCC.
19.3 In the event that Cogenron cures any such default, UCC shall resume
Gas Service, receive steam deliveries and continue under this Contract
for the duration thereof.
Article 20 - Access to UCC's Land
20.1 UCC shall provide as reasonably necessary (without cost to Cogenron
suitable space and access to Cogenron on UCC's Land for the
installation and inspection of the Retrofit Equipment at a location(s)
acceptable to Cogenron and UCC and as near the Point of Delivery as
practicable.
20.2 UCC shall also provide as reasonably necessary (without cost to
Cogenron suitable space and access to Cogenron on UCC's Land for the
installation, inspection, protection and maintenance of Cogenron's
meters at a location(s) acceptable to Cogenron and UCC and as near the
Point of Delivery as practicable. Where electricity or instrument air
is required for the operation of Cogenron's meters or meter regulating
valves, Cogenron shall furnish and install wiring, piping and
equipment necessary to provide such items. Notwithstanding any other
provision of this Contract, maintenance and repair of such wiring,
piping and equipment shall be Cogenron's obligation.
20.3 All UCC's security, safety, and confidentiality requirements shall be
followed, and Cogenron shall exercise reasonable care to not damage or
cause loss to UCC's Plant.
Article 21 - Access to Cogenron's Land
21.1 UCC shall have the right of access to Cogenron's Land, and on all
other premises with respect to which Cogenron has secured easements in
connection with this Contract, at all reasonable limes, for the
purpose of inspecting Cogenron's Plant and inspecting the Gas Service
lines, meters and equipment, removing its property, or any other
proper purpose; provided that any such inspection shall not relieve
Cogenron of its obligation to maintain Cogenron's Plant and the Gas
Service lines, meters and equipment as provided in this Contract. All
Cogenron's security and safety requirements shall be followed, and UCC
shall exercise reasonable care to not damage or cause loss to
Cogenron's Plant.
Article 22 - Indemnification
<PAGE> 18
22.1 It is further agreed that UCC and Cogenron as the case may be, shall
indemnify and hold harmless the other party, and its directors,
officers, employees, heirs, executors, successors and assigns from and
against any and all loss, cost, expense, damages, liability, demands,
claims, actions or causes of action (including the respective
employees and agents of Cogenron and UCC, and third parties), or
damage to or the loss of property (including but not limited to
reasonable attorney's fees) for injury or death of persons (including
the respective employees and agents of Cogenron and UCC, and third
parties) or damage to or the loss of property of customer, company,
and third parties) to the extent caused by, or arising out of, or
resulting from any act, error, omission or negligence (including the
failure to comply with any applicable regulations as required herein)
or vicarious or strict liability of the indemnifying party in
connection with the design, installation, operation or maintenance of
the property and equipment of the parties hereto as required herein,
the steam deliveries and/or Gas Service. It is thus intended that each
party hereto shall be liable, as between the parties hereto, in the
percentage that such party was the cause of any such loss, cost, etc.
This section is intended to satisfy the express negligence test as set
forth by the Texas Supreme Court. Therefore, the parties agree to
indemnify each other for the consequences of their own negligence.
IN WITNESS WHEREOF, this Agreement is signed and executed as of the
date and year written below.
COGENRON INC.
By: Earl Gore
Title: President & CEO
Date:
UNION CARBIDE CORPORATION
By:
Title:
Date:
<PAGE> 19
APPENDIX 3
GAS SPECIFICATIONS
The Gas delivered by UCC and received by Cogenron shall meet the
following quality specifications.
1) contain not more than one-fourth (1/4) grain of hydrogen
sulphide or mor ten (10) grains of sulphur per one hundred (100 cubic feet); and
2) have a gross heating value of not less than one thousand
(1,000) British Thermal Units (Btu) per cubic foot of Gas when saturated with
water vapor; and
3) have a temperature not greater than one hundred and ten
degrees Fahrenheit (I 10"F) or less than forty degrees Fahrenheit (40*F); and
4) contain not more than two percent (2%) by volume of carbon
dioxide or one percent (1%) by volume of oxygen;
5) be commercially free of all liquids, suspended matter, dust,
all gums and gum forming constituents, and other objectionable substances; and
6) contain not more than seven (7) pounds of water vapor per
one million cub of Gas; and
7) have a delivery pressure of 375-405 psig.
<PAGE> 20
APPENDIX 5
BOILER QUALITY WATER SPECIFICATIONS
The boiler quality water delivered by UCC and received by Cogenron
shall meet the following quality specifications:
Sodium LESS THAN 50 ppb
Chloride LESS THAN 20 ppb
Silica LESS THAN 20 ppb
Copper LESS THAN 5 ppb
Iron LESS THAN 10 ppb
Total Solids LESS THAN 1 ppb
Conductivity LESS THAN 15
micromhos
pH 7.0 to 9.0
Total Hydrocarbon LESS THAN 50 ppm
TOC LESS THAN 15 ppm
Hardness LESS THAN 10 ppb
<PAGE> 21
Graphic: Of A Tract of Land Out Of Kohfeldts and Addition To The City of Texas
City, Galveston County, TX
Surveyed October 7, 1984
<PAGE> 1
EXHIBIT: 10.11.2
APPENDIX 7
GROUND LEASE AGREEMENT,
BETWEEN
UNION CARBIDE CORPORATION, LANDLORD
AND
NORTHERN COGENERATION ONE COMPANY, TENANT
DATED
JANUARY 1, 1986
IN
TEXAS CITY, TEXAS
<PAGE> 2
TABLE OF CONTENTS
ARTICLE I: DEFINITIONS..................................................... 1
1.01. Certain Definitions............................................. 1
ARTICLE II: DEMISE; TERM; USE............................................... 3
2.01. Demise of Premises.............................................. 3
2.02. Term and Commencement........................................... 4
2.03. Renewal and Extension........................................... 5
2.04. Use of Premises................................................. 5
ARTICLE III: CONSTRUCTION OF IMPROVEMENTS AND LANDLORD'S IMPROVEMENTS........ 6
3.01. Plans........................................................... 6
3.02. Contractor...................................................... 7
3.03. Construction.................................................... 7
3.04. Compliance Inspections.......................................... 7
3.05. Utilities....................................................... 7
3.06. Payment Certificate............................................. 8
3.07. Ownership of Landlord's Improvements............................ 9
3.08. Tenant's Failure to Complete.................................... 9
3.09. Tenant's Failure to Prosecute the Work.......................... 9
ARTICLE IV: RENT AND ADJUSTMENTS............................................ 9
4.01. Payment of Rent................................................. 9
4.02. Net Lease.......................................................10
ARTICLE V: TAXES, UTILITIES AND ADDITIONAL EXPENSES........................10
5.01. Tenant's Payment of Taxes and Assessments.......................10
5.02. Utility Charges.................................................12
5.03. Liens...........................................................12
5.04. Landlord's Option to Pay or Perform.............................13
ARTICLE VI REPAIR AND MAINTENANCE..........................................13
6.01. Obligation of Repair............................................13
6.02. Safety and Environmental Matters................................13
<PAGE> 3
ARTICLE VII: INSURANCE; INDEMNIFICATION......................................15
7.01. Tenant's Insurance..............................................15
7.02. Maintenance of Insurance........................................15
7.03. Waiver of Subrogation Rights....................................16
7.04. INDEMNITY.......................................................16
ARTICLE VIII: DAMAGE AND DESTRUCTION..........................................17
8.01. Election to Restore.............................................17
8.02. Election to Terminate...........................................17
ARTICLE IX: CONDEMNATION....................................................17
9.01. Total Taking....................................................17
9.02. Partial Taking..................................................18
9.03. Prosecution of Proceedings......................................18
ARTICLE X: TRADE FIXTURES AND OTHER IMPROVEMENTS ON TERMINATION............19
10.01. Ownership of Improvements.......................................19
10.02. Removal of Trade Fixtures by Tenant.............................19
ARTICLE XI: DEFAULTS AND REMEDIES...........................................20
11.01. Events of Default by Tenant.....................................20
11.02. Landlord's Remedies.............................................20
11.03. Events of Default by Landlord...................................21
11.04. Tenant's Remedies...............................................22
11.05. Damage Limitations..............................................22
11.06. Non-Waiver......................................................23
11.07. Remedies Cumulative.............................................23
ARTICLE XII: TRANSFER OF INTERESTS...........................................23
12.01. Assignment and Subletting.......................................23
12.02. Permitted Transfers.............................................23
12.03. Prohibition Against Encumbrances................................24
12.04. Estoppel Certificates...........................................24
ARTICLE XIII: LANDLORD'S RIGHT TO USE PREMISES................................24
ARTICLE XIV: QUIET ENJOYMENT.................................................24
<PAGE> 4
ARTICLE XV: HOLDING OVER....................................................25
ARTICLE XVI: NOTICES.........................................................25
ARTICLE XVII: GENERAL PROVISIONS..............................................26
17.01. Time is of the Essence..........................................26
17.02. Entire Agreement................................................26
17.03. No Agency or Partnership........................................26
17.04. No Merger.......................................................26
17.05. Attorneys' Fees.................................................27
17.06. Governing Law...................................................27
17.07. Partial Invalidity..............................................27
17.08. Binding Effect..................................................27
17.09. Construction....................................................27
17.10. Memorandum of Lease.............................................27
17.11. Confidentiality.................................................27
17.12. Force Majeure...................................................28
17.13. Compliance with Laws............................................28
17.14. Late Payments...................................................28
17.15. Precautionary Filings...........................................28
17.16. Priority of Agreements..........................................29
17.17. Fair Market Value...............................................29
EXHIBIT A: Legal Description of Premises
EXHIBIT A-1: Premises Survey
EXHIBIT B: Cogeneration Site Clearance
EXHIBIT C: Designation of Main Drainage Ditch
<PAGE> 5
GROUND LEASE AGREEMENT
THIS GROUND LEASE AGREEMENT dated as of January 1, 1986 ("Lease") is
made and entered into by and between UNION CARBIDE CORPORATION ("Landlord") and
NORTHERN COGENERATION ONE COMPANY ("Tenant").
W I T N E S E T H:
ARTICLE I
DEFINITIONS
1.01. Certain Definitions. In addition to those certain terms
defined elsewhere in this Lease, the following capitalized terms shall be
defined as set forth below, for purposes of this Lease and all supplements and
amendments hereto, unless otherwise required by the context in which such term
appears:
(1) "Additional Rent" means any and all sums other than Annual
Rent which Tenant is or becomes obligated to pay to Landlord under this
Lease.
(2) "Agreements" means this Lease, the Steam and Electricity
Service Agreement and the Utility Service Agreement.
(3) "Annual Rent" shall have the meaning described in Section
4.01.
(4) "Applicable Law" means all present and future statutes,
regulations, ordinances, resolutions and orders of any Governmental
Authority in any way relating to this Lease, the Premises or Tenant's use
thereof.
(5) "Applicable Rate" means, at any time, the then current
short-term borrowing rate, plus one percent (1%0, of the obligor, not to
exceed the maximum interest rate permitted to be charged by Applicable
Law.
(6) "Commencement Date" means that date for commencement of the
Term of this Lease determined in accordance with Section 2.02 hereof.
(7) "Commencement of Service Date" shall have the same meaning as
described in the Steam and Electricity Service Agreement.
(8) "Contractor" means the general construction contractor or
contractors for construction of Tenant's Plant, selected by Tenant as
provided in Section 3.02.
<PAGE> 6
(9) "Force Majeure" means fire, strike, riot, explosion, flood,
accident, acts of God, the public enemy, governmental laws, ordinances,
rules or regulations (whether valid or invalid), or without limitation by
enumeration, any other acts or circumstances beyond the reasonable control
of the affected party which prevents or delays the performance by Landlord
or Tenant of any obligation imposed upon it hereunder (other than the
payment of Rent). Unscheduled shutdowns due to failure of either party to
properly maintain the equipment for which it is responsible according to
accepted practices shall not be considered as a force majeure event.
(10) "Governmental Authority" means any federal, state, county or
municipal governing body, and any department, agency or board thereof,
having jurisdiction over the Project.
(11) "Improvements" means Tenant's Plant and the Retrofit
Equipment.
(12) "Landlord's Improvements" means those improvements on certain
land as designated in the plans and specifications attached hereto as
Exhibit "B".
(13) "Landlord's Land" means the land owned by Landlord in Texas
City, Texas, situated in the vicinity of the Premises, as such land may be
increased or decreased from time to time, except that the Premises is
expressly excluded from such definition.
(14) "Landlord's Plant" means the plant, including equipment,
rolling stock and all personal property of any kind, owned and operated by
or on behalf of Landlord on Landlord's Land, now or in the future, being
the property and equipment on Landlord's side of the Point of Delivery,
excluding the Retrofit Equipment.
(15) "Lease Year" means each calendar year, or portion thereof,
during the term of the Lease.
(16) "Plans" means the plans and specifications for the
construction of the Improvements, prepared as provided in Section 3.01.
(17) "Point of Delivery" shall be those points specified in the
Steam and Electricity Service Agreement.
(18) "Premises" means the property which is the subject hereof and
leased by Landlord to Tenant and which is described by metes and bounds in
Exhibit A, attached hereto.
-2-
<PAGE> 7
(19) "Project" means the Premises and Tenant's Plant to be
constructed thereon.
(20) "Rent" means Annual Rent and Additional Rent.
(21) "Retrofit Equipment" means that equipment described in the
Steam and Electricity Service Agreement as Retrofit Equipment and owned,
constructed and provided by Tenant on Landlord's Land.
(22) "Steam and Electricity Service Agreement" means the Steam and
Electricity Service Agreement dated as of June 12, 1985, between Landlord
and Tenant providing for the sale and purchase of steam and electricity as
therein provided, as amended from time to time.
(23) "Substantial Completion" means that Tenant's Plant has been
substantially completed in accordance with the Plans and evidenced by a
certificate to such effect executed by Landlord and Tenant. Such
certificate shall not be withheld because certain minor items of
construction or mechanical adjustment remain to be completed.
(24) "Tenant's Plant" means the plant, including equipment, rolling
stock and all personal property of any kind, owned and operated by Tenant
on the Premises, being the property and equipment on Tenant's side of the
Point of Delivery up to and including the Point of Delivery.
(25) "Term" means the term of this Lease, as provided in Sections
2.02 and 2.03.
(26) "Utility Service Agreement" means the Utility Service
Agreement dated as of June 12, 1985, between Landlord and Tenant providing
for the sale of utility service as therein provided, as amended from time
to time.
ARTICLE II
DEMISE; TERM; USE
2.01 Demise of Premises. (a) Subject to the terms and conditions
set forth herein, and in consideration of the covenants of payment and
performance set forth herein, Landlord hereby leases and demises unto Tenant,
and Tenant hereby rents and accepts from Landlord, the Premises, subject to all
existing exceptions, reservations, conditions, restrictions, easements and other
third-party rights and the exception and reservation by Landlord of the
exclusive right to use any wastewater, drainage, utility or product ditches,
conduits or pipelines now located in, under, upon or through the Premises,
whether visible from
-3-
<PAGE> 8
apparent inspection or otherwise, except as may be otherwise expressly provided
by the Agreements. The foregoing shall be subject to the limitations and
indemnification contained in Section 6.02 (b) of this Agreement.
(b) Landlord agrees to inform Tenant of the nature and
approximate location of such facilities or easements on or pertaining to the
Premises, or privilege to install same, of which Landlord is aware. Tenant has
the duty to investigate and inspect the Premises for the purpose of ascertaining
the conditions existing at such Premises; provided, however, that the inability
to visually observe any of such conditions shall not affect Tenant's liability
and responsibilities hereunder. In any event, Tenant shall have the right to
build the Improvements in substantially. the manner originally anticipated as
long as the construction, operation and use thereof does not unreasonably
interfere with the rights of those parties entitled to possession of the
Premises by way of easements, whether express, prescriptive or otherwise.
(c) Tenant may, at Tenant's sole cost, expense and
liability, exercise all of Landlord's rights and privileges pertaining to the
relocation or removal of third party property on the Premises, subject however
to any pre-existing agreements between Landlord and such third party. Tenant
agrees to indemnify and hold Landlord harmless from and against any claims,
costs, damages or liabilities arising in connection with the exercise of such
rights and privileges.
(d) Landlord, its subsidiaries and affiliates, currently
utilize portions of the Premises for pipelines as indicated on the site plan of
D. Engineers, Inc., dated September 30, 1985, and such use shall continue
uninterrupted by this Lease, subject however to the provisions of
Section 2.01(b) above. Landlord shall have the right to evidence in written,
recordable form easements sufficient to reasonably service such pipelines and
this Lease shall thereby be subject to such easements.
2.02 Term and Commencement. Unless sooner terminated as provided in
this Lease, the Term of this Lease will be for a period beginning on the
Commencement Date and ending on June 30, 1999, or such earlier date as the Steam
and Electricity Service Agreement may terminate if such termination is due to
Tenant's default or the mutual agreement of the parties. The Commencement Date
and the date of delivery of possession of the Premises to Tenant shall be the
effective date of this Agreement or such earlier date as may be mutually agreed
by the parties hereto. Notwithstanding the Commencement Date, however, Landlord
shall have the right to use the Premises as a parking lot until such
-4-
<PAGE> 9
time as Tenant has provided satisfactory alternative parking facilities for
Landlord as specified on Exhibit "B" hereto.
2.03. Renewal and Extension. In the event that the parties agree
to extend the Steam and Electricity Service Agreement beyond the initial term
thereof, this Lease shall be extended for the same period of time. In the event
of termination of the Steam and Electricity Agreement (except due to the default
by Tenant) and subject to the continuous operation of Tenant's Plant and the
Retrofit Equipment in accordance with Section 2.04 below and this Lease, the
term of this Lease shall be extended at the option of Landlord and Tenant f or
so long as Tenant's Plant is used for the production of steam or electric
power, provided that if Landlord chooses in its sole discretion not to extend
the term of this Lease, Tenant shall have, the option to purchase the Premises
upon terms mutually agreeable to Landlord and Tenant. In the event Landlord and
Tenant are unable to reach a satisfactory agreement as to acquisition of the
Premises and Tenant still desires to purchase the Premises, the purchase price
shall be the fair market value of the Premises as determined in accordance with
Section 17.17 of this Lease. Within sixty (60) days after Landlord provides
written notice to Tenant of its election not to extend this Lease, Tenant shall
provide written notice to Landlord whether it intends to purchase the Premises.
Conveyance of the Premises to Tenant and payment of the consideration for such
sale shall occur within sixty (60) days after the purchase price is agreed upon
or determined. In the event Tenant fails or refuses to exercise the option
provided for herein, Tenant shall have no continuing right to the Premises after
termination of this Lease, except as may be otherwise provided in this Lease.
The instrument(s) conveying the Premises to Tenant shall contain a restriction
limiting use of the Premises to the same extent limited by this Lease, unless
otherwise approved by Landlord, which approval shall not be unreasonably
withheld as long as the intended use does not potentially interfere with the
ongoing business of Landlord. Landlord and Tenant shall also agree upon such
mutual reciprocal easements and rights and obligations between Landlord and
Tenant as may be necessary to continue use of the Premises, the Improvements and
Landlord's Plant in the same manner contemplated by this Lease. Such restriction
and mutual reciprocal easements shall terminate in the event Landlord becomes
the owner of the Premises or the Premises is merged with Landlord's Land. In the
event of violation of such restriction, Landlord shall have the option to
acquire the Premises in the same manner described above and the Improvements
shall be disposed of in accordance with Article X.
2.04. Use of Premises. Tenant shall have the right to use the
Premises for the following purposes, and only for those purposes: construction
of Tenant's Plant, and the business of
-5-
<PAGE> 10
operating and maintaining Tenant's Plant for the generation and production of
steam and electricity for sale to Landlord and third parties. Any use by Tenant
of the Premises for any other purposes shall require the specific prior written
approval of Landlord thereto. Tenant shall at all times during the Term,
excepting periods of reconstruction due to casualty or condemnation (provided
Tenant diligently and continuously prosecutes the same), continuously operate
Tenant's Plant and the Retrofit Equipment in accordance with the terms of the
Agreements. Notwithstanding the above, however, if Landlord is in default under
the Steam and Electricity Service Agreement, and said Agreement has been
terminated for that reason, Tenant shall have the right for the balance of the
term of any then effective agreement for the sale of electric power generated
by Tenant's Plant to operate and maintain Tenant's Plant. If, however, Tenant is
in default under (i) the existing agreement, as amended, for the sale of
electricity to said public utility of electric power generated by Tenant's Plant
and (ii) the Steam and Electricity Agreement and/or Utility Service Agreement
and Landlord has obtained the full amount of its remedy due to such default,
Tenant may sublease the Premises to said electric public utility for the balance
of the original term of this Lease.
ARTICLE III
CONSTRUCTION OF IMPROVEMENTS AND LANDLORD'S IMPROVEMENTS
3.01. Plans. (a) Tenant shall, without expense to Landlord,
prepare plans and specifications for construction of the Improvements and shall
construct such Improvements as required by the Steam and Electricity Service
Agreement. Such plans and specifications shall include working drawings,
complete for building purposes and sufficient for approval by all Governmental
Authorities. Tenant shall design the Improvements to provide for all surface
water runoff to be delivered in the manner designated on Exhibit "C" hereto.
Tenant shall design the Improvements to conform with all easement obligations of
Landlord and to prevent any damage to pipelines existing on the Premises on the
date of execution of this Lease. Tenant shall comply with all pipeline easement
conditions applicable to Landlord on the Premises.
(b) Tenant, as an independent contractor and not as an agent
or partner of Landlord, shall also construct Landlord's Improvements at no cost
to Landlord on land to be provided by Landlord in accordance with the plans and
specifications. for Landlord's Improvements attached hereto as Exhibit "B".
Landlord's Improvements are hereby expressly agreed not to be part of the
Retrofit Equipment.
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(c) Tenant shall obtain, without expense to Landlord, all
building permits and approvals required by Governmental Authorities before
commencing construction.
3.02. Contractor. (a) Tenant shall retain one or more contractors
(the "Contractor") to construct the Improvements and Landlord's Improvements.
The construction contract to be executed between Tenant and Contractor shall
provide that Contractor shall look solely to Tenant for any payment due under
the construction contract.
(b) Tenant shall require all Contractors to furnish payment
and performance bonds, naming Landlord as a co-obligee, which shall be in such
amount and with such other terms as are reasonably satisfactory to Landlord.
Such bonds shall remain in effect notwithstanding any breach of contract by
Tenant or termination of this Lease. The comprehensive general liability
insurance and indemnification provisions set forth in Article VII shall apply to
the construction of Landlord's Improvements, and Tenant shall require similar
provisions of its Contractors.
3.03. Construction. Upon obtaining required permits and approvals,
Tenant shall commence construction of the Improvements and Landlord's
Improvements and thereafter prosecute same to Substantial Completion. All
construction shall be done substantially in accordance with the Plans, in
compliance with all Applicable Laws, and in a good and workmanlike manner.
Tenant shall pay all bills for labor, materials and supplies in connection with
such construction, and shall obtain releases of liens from the persons or
entities performing such labor or furnishing such materials and supplies, and
all fees for engineering, architectural, legal and other professional services
incurred in connection with such construction.
3.04. Compliance Inspections. Landlord shall have the right to
inspect, at any time during business hours, the Improvements and Landlord's
Improvements and all construction and materials thereof and all plans, drawings,
records and other documents that relate to construction of the Improvements and
Landlord's Improvements. Tenant shall afford Landlord full and free access to
the Improvements and Landlord's Improvements and all such documents. Landlord
shall have no obligation to make any inspections, and if Landlord makes any
inspection, Landlord shall have no responsibility or liability for detecting or
determining deficiency in construction or variance from the Plans.
3.05. Utilities. Except to the extent otherwise provided in the
Steam and Electricity Service Agreement and the Utility Service Agreement,
Tenant shall be responsible for obtaining satisfactory utility service for full
operation of the Improvements without expense to Landlord. As an incident to
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Tenant's occupancy and subject to availability, capacity and sufficient prior
notice, Landlord will endeavor to provide Tenant with electric power sufficient
to enable Tenant to commence initial operations in Tenant's Plant on the
Premises or restart Tenant's Plant in the event of a power shutdown. Such power
shall be generated from Landlord's qualifying cogeneration facilities under
Federal Energy Regulatory Commission guidelines. Tenant's use of power supplied
by Landlord shall be strictly limited to use at Tenant's Plant and may not be
held for resale or distribution to any other party. Landlord shall have the
right to terminate the supply of electric power if at any time such activity
would endanger the operations at Landlord's Plant or if required under
Applicable Laws. The agreement of the Landlord to the foregoing is based on the
assumption that the ratepayers of the utility in whose service area the Tenant
is located will not be substantially adversely affected as a result of the
activity of Landlord or Tenant anticipated by this Section. If at any time it
is claimed by governmental agencies exercising jurisdiction in such area under
Applicable Laws that Landlord is in violation of Applicable Laws, that Landlord
is required to obtain a Certificate of Convenience and Necessity or that the
services provided by Landlord are deemed evidence that it is operating or
holding itself out as a public utility, any rights or obligations with regard to
supplying electric power shall thereby terminate. Landlord shall not be liable
to Tenant for any claims, damages, loss or liability due to (i) Landlord's
inability or failure to furnish any of the power pursuant to the provisions of
this Section on account of any force majeure occurrences, (ii) any failure of
Landlord's supplier of electricity to provide adequate and reliable service
which affects Landlord's ability to provide power to Tenant, or (iii) any
failure, interruption or curtailment of any of the power due to equipment, labor
or other problems which do not arise out of the gross negligence or willful
misconduct of Landlord, its employees, agents or contractors. Tenant shall fully
and promptly pay, perform, discharge, defend, indemnify and hold Landlord
harmless from and against any claim, demand, action or suit, loss, cost, damage,
fine, penalty or expense (including reasonable attorneys' fees) resulting from
Landlord delivering electric power to Tenant's Plant.
3.06. Payment Certificate. At the time of Substantial Completion,
Tenant shall deliver to Landlord a certificate signed by Tenant and Contractor
certifying that all work for which payment is due under the Construction
Contract has been completed and fully paid for. Such certificate shall
constitute Tenant's representation that the materials have been physically
incorporated into the Improvements or Landlord's Improvements free of liens and
encumbrances and that the work conforms to the Plans and Applicable Law.
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3.07. Ownership of Landlord's Improvements. Upon Substantial
Completion of Landlord's Improvements, ownership and possession of Landlord's
Improvements shall be transferred to Landlord by Tenant. Tenant shall promptly
provide Landlord with whatever documentation may reasonably be required by
Landlord to effectively transfer such ownership.
3.08. Tenant's Failure to Complete. If the Commencement of Service
Date does not occur within thirty-six (36) months after the effective date of
execution of this Lease, unless the prior written approval of Landlord thereto
is received, Landlord may by written notice delivered to Tenant within ninety
(90) days after the expiration of said thirty-six (36) month period exercise any
or all of the following options:
(a) Landlord, may, without cost to Landlord, terminate this
Lease and require the Premises to be returned to the condition in which it
existed on the Commencement Date, within a reasonable period thereafter, but not
to exceed nine (9) months after termination.
(b) Landlord may elect to purchase the unfinished
Improvements at the fair market value thereof, complete construction of the
Improvements and operate the Improvements as it may deem appropriate.
3.09. Tenant's Failure to Prosecute the Work. If at any time prior
to the Commencement of Service Date, Tenant fails to undertake substantial
construction towards completion for a continuous period of ninety (90) days for
reasons other than force majeure, Tenant shall have thirty (30) days in which to
cure such failure after receipt of written notice thereof from Landlord. If
Tenant fails to so cure this failure, Landlord may exercise any or all of the
remedies specified in Section 3.08.
ARTICLE IV
RENT AND ADJUSTMENTS
4.01. Payment of Rent. Tenant shall pay Rent as follows:
(a) Annual Rent beginning on the Commencement of Service
Date, as follows: $30,000 for calendar years 1987 and 1999, and $60,000 a
year for calendar years 1988 through 1998. Tenant shall pay Annual Rent in
advance commencing with the Commencement of Service Date and thereafter
pay the appropriate Annual Rent on January 1 of each calendar year of the
Term thereafter; and
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(b) In the event of termination of the Agreements or any
other agreement providing substitute or similar rights and benefits to
Landlord, the Annual Rent due under this Lease shall be adjusted to equal
the fair market rental rate for the Premises and other rights provided
Tenant under this Lease and, in any event shall not be less than the
Annual Rent provided in (a) above. The fair market rental rate shall be
that rate agreed upon by Landlord and Tenant as the prevailing market rate
and, in the event the parties are not able to reach agreement, the rate
shall be determined in accordance with the procedure described in Section
17.17, provided that such appraisers shall determine the fair market
rental value on a net lease based upon use of the Premises for industrial
activity for the remainder of the term of this Agreement.
(c) Additional Rent, including but not limited to those
items payable by Tenant to Landlord pursuant to Article V, within twenty
(20) days of the receipt of Landlord's invoice or statement for same, or
if this Lease provides another time for the payment of certain items of
Additional Rent then at such other time.
Rent shall be paid in United States dollars without counterclaim, set off or
deduction and without demand to Landlord at its address for receipt of notices
hereunder, or at such other place in the United States of America as Landlord
may from time to time designate in writing.
4.02. Net Lease. This Lease is a net lease, and Tenant shall pay all
costs, taxes and assessments the payment for which Landlord or Tenant is or
becomes liable by reason of its estate or interest in the Project or this Lease,
and which are connected with or arise out of the possession, use, condition,
occupancy, maintenance, repair or rebuilding of the Project, or a portion
thereof, except as may be otherwise provided in the Steam and Electricity
Service Agreement, the Utility Service Agreement or in Section 6.02(b) of this
Lease.
ARTICLE V
TAXES, UTILITIES AND ADDITIONAL EXPENSES
5.01. Tenant's Payment of Taxes and Assessments. (a) Except as
otherwise provided herein, Tenant shall pay and discharge, prior to the
imposition of any interest or penalty or the attachment of any lien for
delinquency in payment, all taxes, assessments and other rates and charges,
excises, levies, and other governmental and similar charges, of every character,
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directly relating to the Project, and any interest and penalties thereon, which
at any time during or in respect to the Term may be levied or assessed against,
or may become or be a lien upon, or in respect of the interest of Tenant in the
Project, or a portion thereof and the possession, use, occupancy, condition,
maintenance, repair or rebuilding of the Project by Tenant, or a portion
thereof. If at any time during the term of this Lease, the present method of
taxation or assessment shall be changed and another shall be substituted
therefor, Landlord and Tenant agree to amend this Lease in order to reflect such
change and return the parties to the original position intended by the Lease.
Nothing in this Section 5.01 shall require Tenant to pay any income or excess
profits tax of Landlord, unless such tax is in lieu of or a substitute (in whole
or in part) for another tax or assessment upon or against the Project, which, if
such other tax or assessment were in effect, would be payable by Tenant. Tenant
shall also pay all special assessments for public or other civic improvements
assessed or imposed against the Premises or the Improvements. In the event any
such assessment also applies to other property of Landlord and is not reasonably
capable of being equitably apportioned between Landlord and Tenant, that method
of allocation used by the public agency imposing the assessment shall be used.
If any such tax, assessment or other charge levied or assessed against the
Project may legally be paid in installments, Tenant may pay same in installments
and shall be obligated to pay only such installments as are allocable to periods
within the Term. Tenant shall promptly furnish to Landlord proof of the payment
of any tax, assessment, or other charge payable by Tenant hereunder.
(b) Landlord shall pay ad valorem real property taxes for
the Project directly to the appropriate taxing authority. However, Tenant shall
be liable to Landlord for, and shall pay to Landlord, upon receipt of
appropriate evidence that such taxes have been paid, (i) the property taxes for
the Premises, determined as the proportion that the acreage of that portion of
the Premises included in the statement for such tax bears to the acreage of all
the land included in such statement; and (ii) the property taxes for Tenant's
Plant, determined as the amount allocable for that portion of Tenant's Plant
included in the statement for such tax. Real property taxes on the Premises
which are levied or assessed for the tax years in which this Lease commences and
terminates, shall be prorated based on the portion of such tax years included in
the Term. Notwithstanding the above, to the extent that the Improvements, or
portion thereof, are considered as personal property and as required by law,
Tenant shall render the Improvements, or any portion thereof, and shall pay any
property taxes thereon directly to the appropriate taxing authority.
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(c) Landlord or Tenant, as appropriate, shall promptly send
to the other party a copy of any tax bill, assessment, or other notice
pertaining to ad valorem property taxes due against the Project that indicates
an increase in the assessed valuation thereof or an increase in the amount of
such taxes. Landlord and Tenant shall cooperate in timely legal attempts to
render the Project and reduce the amount of any tax thereon prior to its
becoming due. Tenant shall have the right to participate on its own behalf in
any proceedings affecting the assessed valuation of the Project. After
consultation with Landlord, Tenant may, at its cost and expense, contest the
existence, amount or validity of any such taxes by appropriate proceedings that
prevent the attachment of any lien against the Project, or portion thereof, and
the sale, or loss of the Project, or portion thereof, and Tenant shall not be
required, and Landlord shall not have the right, to pay any tax, assessment or
other charge against the Project or portion thereof, for the duration of such
contest; provided Tenant gives such security as may be required in such
proceedings to ensure such payment and prevent any sale or loss of the Project,
or portion thereof, by reason of nonpayment; and, provided further, that
Landlord will not be in any danger of criminal liability by reason of such
nonpayment. Tenant shall keep Landlord informed of the status and progress of
any contest and provide copies of all material notices, filings and
correspondence. Landlord reserves right to become an active participant in any
such proceeding to the extent necessary to protect its interests. Tenant will
endeavor not to take any action which would have a material adverse impact on
Landlord's Land and Landlord's Plant.
(d) Notwithstanding any other provision of this Section
5.01, to the extent that the Steam and Electricity Service Agreement or the
Utility Service Agreement provide for payment by Landlord by any amounts
specified in this Section 5.01, such agreements shall control.
5.02 Utility Charges. Except to the extent otherwise provided by
the Utility Service Agreement and the Steam and Electricity Service Agreement,
Tenant shall pay all charges for connection for and use of gas, electricity,
water, sewer and all other utilities serving the Project. Landlord shall not be
liable to Tenant for any failure or interruption of any service being furnished
to the Project nor shall such failure or interruption result in an abatement of
Rent unless the same results from the, negligence or intentional act of
Landlord, its invitees or licensees.
5.03 Liens. Tenant or Landlord, as applicable depending on who is
legally responsible, shall promptly remove and discharge of record (whether by
payment, filing the necessary bond, order of a court of competent jurisdiction
or otherwise),
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without expense to the other party, all liens, encumbrances and charges upon the
Project, Tenant's leasehold interest in the Premises, or the Retrofit Equipment,
which arise out of the owner's possession, use, occupancy, condition,
maintenance, repair, building or rebuilding of the Project or the Retrofit
Equipment, or by reason of labor or materials furnished or claimed to have been
furnished to Tenant for the Project or the Retrofit Equipment.
5.04 Option to Pay or Perform. If Tenant or Landlord, as
applicable, fails to make a payment or perform an act for which it is obligated
hereunder, then, subject to the provisions of Section 5.01(c), the other party
may (but need not), after notice to or demand upon the responsible party and
without waiving any default or releasing the responsible party from any
obligation, make such payment or perform such act for the account and at the
expense of the responsible party. The responsible party shall pay to the other
party all amounts so paid by the other party and all necessary and incidental
costs and expenses (including reasonable attorneys' fees and expenses) incurred
in connection with the performance of any such act by the other party, together
with interest at the Applicable Rate from the date the other party makes such
payment or incurs such costs and expenses until payment by the responsible
party.
ARTICLE VI
REPAIR AND MAINTENANCE
6.01 Obligation of Repair. Except as otherwise expressly provided
herein, Tenant waives any right to make repairs at Landlord's expense which may
be provided for in any law now or hereafter in effect. Tenant shall maintain and
repair and keep the Improvements in normal working order. Landlord, at its
option, shall have the right of access at all times to maintain in normal
working order the surface water runoff drainage system described on Exhibit "C".
6.02 Safety and Environmental Matters. (a) Tenant shall not cause
or permit any nuisance or extra hazardous condition to exist or be maintained
upon the Premises and shall eliminate or remove the same promptly upon any
notice thereof. Tenant shall not cause or permit the storage, production,
generation, emission, disposal or burial of any hazardous or toxic materials or
substances upon the Premises and shall cease and eliminate any such activities
and clean up and otherwise remove any wastes or other materials resulting
therefrom promptly upon the request of Landlord or any Governmental Authority.
Notwithstanding the above prohibitions, however, such prohibitions as to use or
storage only shall not apply (i) to any condition, material or substance usually
and necessarily required
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in the normal course of steam and electricity generation (ii) if Landlord
consents to any such condition, material or substance being used or stored on
the Premises after receiving prior written notice thereof from Tenant, or (iii)
those matters which Landlord is responsible for in accordance with Section
6.02(b).the requirements of this Section 6.02, Tenant at its sole cost and
expense shall comply fully with all Applicable Law relating to the use,
operation or maintenance of the Project. In the event that Tenant causes any
nuisance or any dangerous, harmful, hazardous, toxic or unhealthful condition on
the Premises, Tenant shall be fully liable for any damages, penalties or fines
relating to any such condition.
(b) On and after the Commencement Date, Landlord shall fully
and promptly pay, perform, discharge, defend, indemnify and hold harmless
Tenant, its parent and subsidiaries and affiliates, and their respective
directors, officers and employees (and no other party) from and against any
claim, demand, action or suit, loss, cost, damage, fine, penalty or expense
(including reasonable attorneys' fees) resulting from any Environmental Claim
arising out of any operations conducted, commitment made, product manufactured
or any action taken or omitted by Landlord with respect to the Premises
(including but not limited to the business operations, transactions or conduct
of the business directly or indirectly related thereto) during periods prior to
the Commencement Date (excluding any liabilities expressly assumed by Tenant
pursuant to this Agreement); provided, however, that on and after the
Commencement Date, Tenant shall fully and promptly pay, perform and discharge,
defend, indemnify and hold harmless Landlord and its directors, officers and
employees from and against any claim, demand, action or suit, loss, cost,
damage, fine, penalty or expense (including reasonable attorneys' fees)
resulting from any Environmental Claim arising out of any operations conducted,
commitment made, product manufactured, aggravation of existing conditions by
Tenant or any other action taken or omitted by Tenant, its parent, subsidiaries,
affiliates successors and assigns, with respect to the Premises (including but
not limited to business operations, transactions or conduct of the business
directly or indirectly related thereto) solely during periods after the
Commencement Date. To the extent Tenant may be reasonably expected to discover
the presence of any conditions which may give rise to Environmental Claims upon
conducting the investigation described in Section 2.01, Landlord's liability
shall terminate upon curing any condition disclosed in writing to Landlord
pursuant to said investigation. In any event, Landlord shall have no liability
for pre-existing conditions after the substantial completion of the site
preparation, borings, footings and foundations for Tenant's Plant, except to the
extent specific written notice to such effect is provided to Landlord prior to
completion of such
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site preparation. Nothing contained herein shall have the effect of relieving
Landlord or Tenant from any liability prescribed by Applicable Law with regard
to Environmental Claims. For purposes of this subsection "Environmental Claim"
shall mean any claim or demand by any governmental authority or any person for
personal injury (including sickness, disease or death), property damage or
damage to the environment resulting from the release of any chemical, material
or emission into the environment at or in the vicinity of the Premises.
ARTICLE VII
INSURANCE; INDEMNIFICATION
7.01 Insurance. (a) Tenant shall maintain at its expense fire and
extended coverage insurance on the Project and the Retrofit Equipment in amounts
as are reasonably satisfactory to Landlord, which insurance shall cover all
personal property, improvements and betterments, including removable trade
fixtures, located in the Project and the Retrofit Equipment and on all other
additions, improvements and betterments made by Tenant.
(b) Tenant shall, at its own expense, maintain a policy or
policies of comprehensive general liability insurance with the premiums thereon
fully paid on or before due date. Such policy or policies shall provide for
proper limits, in amounts reasonably satisfactory to Landlord.
(c) Tenant shall comply with all applicable Workers'
Compensation laws and provide Workers' Compensation insurance, if required, for
all persons employed by it on the Project or the Retrofit Equipment or in
connection with the business conducted pursuant to this Lease and shall pay any
and all contributions, taxes and costs of such insurance and benefits payable
thereunder which are required to be withheld and/or paid by any employer under
the provisions of any applicable present or future law, ruling and regulation.
(d) Landlord will continue to maintain at its expense fire
and extended coverage insurance on its property in the vicinity of the Premises
and comprehensive general public liability insurance. Such insurance shall be in
amounts and provide such coverage as may be carried by Landlord as of the
Commencement Date and shall be consistent with reasonable risk management.
7.02 Maintenance of Insurance. Landlord and Tenant shall review the
limits for the above required insurance policies annually and said policy limits
shall be increased to proper limits as circumstances warrant. All policies of
insurance which Tenant must provide pursuant to the provisions of this Lease,
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except Workers' Compensation insurance, shall be issued by solvent. insurance
carriers licensed to do business in the State of Texas and having a Best's
rating of at least XIII, A, or better, and shall be in form reasonably
satisfactory to Landlord. Tenant shall provide to Landlord copies of insurance
binders (or certificates in lieu thereof) in respect to the insurance policies
to be maintained in compliance with this Article no later than fifteen (15) days
prior to the date on which such policies are to be effective and copies or
certificates of such policies as soon as possible after the effective date of
such policies. Each such binder and policy shall provide that it may not be
cancelled without at least fifteen (15) days' notice to Landlord. If at any time
Tenant fails to provide insurance as required by the foregoing provisions of
this Article, Landlord, upon ten (10) days' notice to Tenant, may provide such
insurance as Tenant's agent and in Tenant's name, and until such time as Tenant
so insures (which for the purposes of this provision may only be on a subsequent
renewal date), Tenant shall reimburse Landlord for premiums paid by Landlord in
respect of same plus interest at the Applicable Rate from the date of Landlord's
payment within twenty (20) days of receipt of Landlord's statement and evidence
of payment of same.
7.03 Waiver of Subrogation Rights. Landlord and Tenant each hereby
waives any and all rights of recovery, claim, action or cause of action, against
the other, their respective agents, officers, or employees for any loss or
damage that may occur to the Project or the Retrofit Equipment, or any personal
property of such party therein, which may arise by reason of fire, the elements,
or any other cause which could be insured against under the terms of standard
fire and extended coverage insurance policies, regardless of cause or origin,
including negligence of the other party hereto, its agents, officers or
employees, and covenants that no insurer shall hold any right of Subrogation
against such other party.
7.04 INDEMNITY. IT IS FURTHER AGREED THAT, EXCEPT AS PROVIDED
ELSEWHERE IN THIS LEASE, LANDLORD AND TENANT, AS THE CASE MAY BE, SHALL
INDEMNIFY AND SAVE THE OTHER PARTY, AND ITS DIRECTORS, OFFICERS, EMPLOYEES,
HEIRS, EXECUTORS, SUCCESSORS AND ASSIGNS, HARMLESS FROM AND AGAINST ANY AND ALL
LOSS, COST, EXPENSE, DAMAGES, LIABILITY, DEMANDS, CLAIMS, ACTIONS OR CAUSES OF
ACTION (INCLUDING BUT NOT LIMITED TO REASONABLE ATTORNEYS' FEES IN THE EVENT OF
ONE HUNDRED PERCENT (100%) LIABILITY OF SUCH PARTY FOR SUCH LOSS, COST, ETC.
FOR INJURY TO OR DEATH OF PERSONS (INCLUDING THE RESPECTIVE EMPLOYEES AND AGENTS
OF THE PARTIES HERETO AND THIRD PARTIES), OR DAMAGE TO OR THE LOSS OF PROPERTY
(INCLUDING THE RESPECTIVE PROPERTY OF THE PARTIES HERETO AND THIRD PARTIES) TO
THE EXTENT CAUSED BY, OR ARISING OUT OF, OR RESULTING FROM ANY ACT, ERROR,
OMISSION OR NEGLIGENCE (INCLUDING THE FAILURE TO COMPLY WITH ANY APPLICABLE
REGULATIONS AS REQUIRED
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HEREIN) OR VICARIOUS OR STRICT LIABILITY OF THE INDEMNIFYING PARTY IN
CONNECTION WITH THE DESIGN, INSTALLATION, OPERATION OR MAINTENANCE OF THE
PROPERTY AND EQUIPMENT OF THE PARTIES HERETO AS REQUIRED HEREIN. IT IS THUS
INTENDED THAT EACH PARTY SHALL BE LIABLE, AS BETWEEN THE PARTIES HERETO, IN THE
PERCENTAGE THAT SUCH PARTY WAS THE CAUSE OF ANY SUCH LOSS, COST, ETC.
ARTICLE VIII
DAMAGE AND DESTRUCTION
8.01 Election to Restore. If during the Term, all or any part of
the Project or the Retrofit Equipment is destroyed or damaged by fire or other
casualty (a "casualty") then in such event, unless this Lease is terminated as
hereinafter provided, Tenant shall immediately give Landlord notice thereof and
repair and reconstruct the Project to a condition substantially equivalent to
its original condition and substantially in accordance with the Plans (but in
any event in compliance with all Applicable Law).
8.02 Election to Terminate. In the event that Tenant is unable to
restore the Project within six (6) months of any such casualty to substantially
the condition in which it existed prior to such casualty, Tenant shall have the
election, exercisable by written notice to Landlord to be given within fifteen
(15) days after the expiration of such six (6) month period, to terminate this
Lease as of the date of such casualty. In the event of such termination,
Landlord shall have the right to:
(i) Require Tenant to clear the Premises and restore the Premises
to the condition in which it existed on the Commencement Date within a
reasonable period thereafter, but not to exceed nine (9) months after such
termination.
(ii) Elect to purchase the Improvements, in whole or in part, at
the fair market value thereof.
In the event of such termination, Tenant shall also be liable for the removal or
elimination of any nuisances, dangerous, harmful or unhealthy conditions or
governmental violations arising therefrom.
ARTICLE IX
CONDEMNATION
9.01 Total Taking. If there is a total or constructive total taking
of the Project and the Retrofit Equipment in condemnation proceedings or by any
right of eminent domain, this Lease shall terminate on the date of such taking
and the Rent
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shall be prorated to the date of such taking. For the purposes of this Section
9.01, a "constructive total taking" means a taking of so much of the Project and
the Retrofit Equipment that the remaining portion cannot be used by Tenant for
the same purpose as before such taking. The award or awards for such taking
shall be paid to Tenant and Landlord as their interests may appear.
9.02 Partial Taking. If there is less than a constructive total
taking of the Project and the Retrofit Equipment, this Lease shall terminate as
to the portion of the Project and the Retrofit Equipment so taken, and from and
after the date of such taking the Annual Rent shall be reduced by just
proportion. Until the amount of the reduction in Annual Rent shall have been
determined, Tenant shall continue to pay to Landlord the Annual Rent provided
herein, it being understood, however, that when the amount of the abatement is
determined, Landlord shall refund to Tenant the amount of Annual Rent paid from
the date of the taking which is in excess of the amount to which the Annual Rent
has been reduced by such abatement. Subject to the provisions of the of any such
taking, Tenant shall promptly restore, repair, replace and rebuild the remaining
portion of the Project and the Retrofit Equipment to substantially the former
condition, and shall restore Tenant's Plant and the Retrofit Equipment, if
affected by the taking in order to perform the function originally intended. In
the event the amount of proceeds obtained from such taking is insufficient to
restore Tenant's Plant and the Retrofit Equipment as above provided, then Tenant
shall not be required to restore and a total taking shall be deemed to have
occurred, provided that Tenant shall be required to clear the Premises and
restore the Premises (or the remainder thereof) to the condition in which it
existed on the Commencement Date within a reasonable period after such taking,
but not to exceed nine (9) months thereafter. Tenant shall provide written
notice to Landlord of its election within thirty (30) days after final
determination that the proceeds of such taking will be less than the costs of
restoration, and, in any event, within ninety (90) days after such taking,
otherwise it will be deemed that Tenant has elected to restore as provided
herein. The award or awards payable for any taking of the type described in this
Section 9.02, less than reasonable costs of determination of the amount thereof
(such net amount being hereinafter called the "Condemnation Proceeds"), shall be
paid to Tenant and Landlord as their interests may appear.
9.03 Prosecution of Proceedings. Landlord and Tenant will cooperate
in the prosecution of any claim for damages arising by virtue of any proceeding
described in this Article IX. Landlord and Tenant shall each have the right to
participate in any condemnation proceeding to present its claim and obtain
suitable compensation.
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ARTICLE X
TRADE FIXTURES AND OTHER
IMPROVEMENTS ON TERMINATION
10.01 Ownership of Improvements. Tenant shall own the Improvements
as specified in the Steam and Electricity Service Agreement. Landlord shall
have the option to purchase the Improvements as provided in the Steam and
Electricity Service Agreement. However, in the event that the parties fail to
agree on a purchase price for Tenant's Plant or the Retrofit Equipment at the
expiration or earlier termination of the Term, Landlord and Tenant shall
negotiate in good faith to reach a mutually satisfactory disposition of such
property. In the event that the parties fail to agree on disposition of all or
part of such property, Landlord may require restoration of all or part of the
Premises as it deems appropriate to the condition in which it existed at the
Commencement Date.
10.02 Removal of Trade Fixtures by Tenant. Tenant may remove its
trade fixtures, personal property and rolling stock and any special improvements
installed by Tenant at its expense which are in addition to the Improvements
which Tenant is obligated to install hereunder and which are not attached to the
Premises, provided that Landlord's estate value is not thereby diminished, at
any time or times provided:
(i) Such removal must be made not later than thirty (30) days
after the date this Lease is terminated and be performed in such manner as
to minimize to the extent reasonably possible any interference with or
disturbance of work then being performed by Landlord in or on the Project;
(ii) Tenant is not then in default hereunder; and
(iii) Such removal is effected without damage to the Project or the
Retrofit Equipment, other than minor damage reasonably anticipated in such
removal operations (or Tenant promptly repairs all damage caused by such
removal), and Tenant pays all cost of clearing and removal of debris
caused by or resulting from such removal.
Landlord shall not be responsible or liable for any damage to or other loss of
such trade fixtures, personal property, rolling stock and special improvements
notwithstanding Landlord's possession of the Project and the Retrofit Equipment
at the termination of this Lease. All trade fixtures, personal property, rolling
stock and special improvements on the Project which Tenant does not remove by
the end of thirty (30) days after the termination of this Lease shall, without
compensation to Tenant, become the property of Landlord. Tenant shall deliver to
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[NOTE: THE TEXT IN THIS PAGE WAS TRANSFERED TO PREVIOUS PAGE]
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Landlord within thirty, (30) days after termination of this Lease a bill of sale
sufficient to properly evidence transfer of such Retrofit Equipment, fixtures,
property, stock and improvements, provided that delivery of such bill of sale
shall not be a prerequisite to the transfer of ownership of such property to
Landlord.
ARTICLE XI
DEFAULTS AND REMEDIES
11.01 Events of Default by Tenant. The following shall each
constitute an Event of Default by Tenant under this Lease:
(a) If Tenant defaults under the Steam and Electricity Service Agreement
and such default results in termination of the Steam and Electricity
Service Agreement; or
(b) Tenant has a material failure to comply with Applicable Law as
required in Section 6.02 of this Lease and such failure is not cured
within forty-five (45) days after receipt of notice from Landlord,
or, if it is not feasible to perform such obligation fully within
said period, if Tenant shall not have promptly commenced to cure
said failure within said period, and thereafter diligently prosecute
the curing of such failure to conclusion.
11.02 Landlord's Remedies. (a) Landlord may, at its sole option, in
the event of an occurrence of an Event of Default as defined in Section 11.01,
exercise the following remedies provided for in this Section by written notice
of default to Tenant, which shall constitute the sole and exclusive remedies
available to Landlord in connection with an Event of Default under this Lease;
and provided that Landlord shall be required to mitigate any damages that it
incurs as a result of such default, which mitigation obligation shall decrease
the amount otherwise payable by Tenant under this Section 11.02:
In the Event of Default as above described and subject to the
foregoing, Landlord may exercise its option to acquire Tenant's Plant as
provided in Section 10.02, free and clear of all liens, claims and
encumbrances or agreements. Such option must be exercised within thirty
(30) days after the termination of this Lease. Closing of the transfer of
the Project shall occur within thirty (30) days after the exercise of said
option. In the event Landlord chooses not to exercise the option provided
above or the parties are not able to agree upon a purchase price for the
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Project, Tenant shall have the option to sublease the Premises to a
qualified operator reasonably satisfactory to Landlord who agrees to
comply with the terms of this Lease and complies with the terms of the
Steam and Electricity Agreement and the Utility Service Agreement for any
transferee or assignee. There shall be no continuing default in this Lease
and Landlord shall be satisfied that the benefits obtained from the Steam
and Electricity Service Agreement and the Utility Service Agreement will
not be interrupted or materially adversely affected. In the event Tenant
is not able or refuses to comply with the foregoing, Landlord may
terminate this Lease. In the event of such termination, Tenant shall be
liable to Landlord for a sum of money equal to the total of (i) the unpaid
Rent earned at the time of termination and Additional Rent, plus interest
thereon at the Applicable Rate from the due date until paid, and (ii) any
other sum of money and damages owed by Tenant to Landlord using a discount
rate of twelve percent (12%).
In the event that Tenant cures any such default, Landlord may elect to reinstate
this Lease and continue under this Lease for the duration of the Term.
(b) For any failure of Tenant to perform any of its obligations under
this Lease other than an Event of Default, Landlord shall have the right to
enforce such obligations by injunction or mandamus action in a court of law
having jurisdiction thereof, including the right to receive any damages, costs,
attorneys' fees and other expenses owed to Landlord due to such failure of
performance.
11.03 Events of Default by Landlord. The following shall each
constitute an Event of Default by Landlord under this Lease:
(a) Failure of Landlord to perform any of its material obligations
under this Lease and such failure is not cured within forty-five (45) days
after receipt of notice from Tenant, or, if it is not feasible to perform
such obligation fully within said period, if Landlord shall not have
promptly commenced to cure said failure within said period, and thereafter
diligently prosecute the curing of such failure to conclusion; or
(b) The occurrence of any of the following:
(i) Landlord's bankruptcy or insolvency or the initiation of
any proceeding, voluntary or involuntary, against Landlord under the
bankruptcy or insolvency laws, or Landlord's failure to meet its
debts in the ordinary course of business;
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provided, however, that there shall be no Event of Default if,
within ten (10) days from the written receipt of notice from Tenant
to terminate for such default, Landlord as debtor in possession or
Landlord's trustee, receiver, assignee or custodian, whichever is
obligee under this Lease, in writing affirms this Lease, the Steam
and Electricity Service Agreement and the Utility Service Agreement
and demonstrates to Tenant's satisfaction the ability to fulfill its
or their obligations under this Lease, the Steam and Electricity
Service Agreement and the Utility Service Agreement;
(ii) Landlord makes an assignment of all or a substantial
part of Landlord's Plant for the benefit of creditors.
11.04 Tenant's Remedies. Tenant may, in the event of an occurrence
of an Event of Default as defined in Section 11.03, exercise any or all of the
following remedies by written notice of default to Landlord, which shall
constitute the sole and exclusive remedies available to Tenant in connection
with this Lease, and provided that Tenant shall be required to mitigate any
damages that it incurs as a result of such default, which mitigation obligation
shall decrease the amount otherwise payable by Landlord under this Section
11.04:
(a) Tenant may terminate this Lease. In the event of such
termination, Tenant shall vacate the Premises and may disconnect
and/or remove the Retrofit Equipment, after reasonable notice to
Landlord, provided entry on Landlord's Land is done in accordance
with Landlord's safety and security requirements.
(b) Tenant may elect to continue under this Lease for the
term of the Steam and Electricity Service Agreement and for such
longer term as may be permitted in Section 2.03.
In the event that Landlord cures any such default, Tenant may elect to reinstate
this Lease and continue under this Lease for the duration of the Term.
11.05 Damage Limitations. Notwithstanding any provision of this
Lease to the contrary, neither party shall be liable for any special, incidental
or consequential damages, including without limitation, loss of profits,
suffered by the other party due to this Agreement for the existence, use or
operation of the Improvements or Landlord's Plant. Landlord shall in no event
and under no circumstances whatsoever be liable
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for the cost or value of Tenant's Plant, Tenant's leasehold interest in the
Premises or the Retrofit Equipment or any other equipment provided by Tenant
hereunder due to the failure of Tenant's Plant to qualify for any reason
whatsoever as a qualifying cogeneration facility pursuant to the Federal Energy
Regulatory Commission Rules or similar applicable rules promulgated by any
successor state or federal regulatory body or bodies or to maintain an exemption
from the Power Plant and Industrial Fuel Use Act of 1978 and applicable
regulations thereunder.
11.06 Non-Waiver. Failure by any party to declare any default
immediately upon occurrence thereof, or delay in taking action in connection
therewith, shall not waive such default, but such party shall during the
continuance of such default have the right to declare such default at any time
and take such action as provided hereunder. Waiver of any right for any default
shall not constitute a waiver of any right for either a subsequent default of
the same obligation or for any other default.
11.07 Remedies Cumulative. All rights, privileges and remedies
afforded either of the parties hereto by this Lease shall be deemed cumulative
and the exercise of any one of such rights, privileges and remedies shall not be
deemed to be a waiver of any other right, privilege or remedy provided for
herein.
ARTICLE XII
TRANSFER OF INTERESTS
12.01 Assignment and Subletting. Except as otherwise provided in
this Article XII, Landlord and Tenant shall not assign, convey or otherwise
transfer any estate, right, title and interest hereunder and/or in the Project,
or any portion thereof, without the prior consent of the other party and any
assignment in violation of this provision shall be void. This Lease shall be
binding upon and shall inure to the benefit of the parties and their successors
and permitted assigns.
12.02 Permitted Transfers. Either party may assign its rights and
obligations under this Lease, subject to the prior written approval of the other
party hereto, which approval shall not be unreasonably withheld, to any
subsequent owner of all or substantially all of the assets of Tenant's Plant and
the Retrofit Equipment or Landlord's Plant, as the case may be, if such
subsequent owner accepts the assignment of this Lease and assumes the
obligations of the conveying party hereunder; provided, however, such right may
only be exercised by Tenant if it first complies with the requirements set forth
in the Steam and Electricity Service Agreement to permit Landlord a first right
of
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refusal with respect to such sale. Upon receipt by the other party of written
documentation of such assignment and assumption, the conveying party shall be
released from all further liability and obligation hereunder. Either party shall
have the right to assign this Lease to a subsidiary or affiliate of such party
without the consent of the other party; provided that the assigning party shall
not be released from its obligations hereunder.
12.03 Prohibition Against Encumbrances. It is specifically agreed
and understood that neither Tenant nor any of its successors or assigns may
assign, encumber or hypothecate this Lease or any interest therein to secure
financing for the purchase of Tenant's Plant, the Retrofit Equipment or Tenant's
leasehold interest in the Premises, unless otherwise agreed by Landlord in
writing.
12.04 Estoppel Certificates. At the request of any party hereto, the
other party will execute an estoppel certificate in favor of the requesting
party or any other third party who may reasonably require such certificate,
certifying to such matter as such party may reasonably require.
ARTICLE XIII
LANDLORD'S RIGHT TO USE PREMISES
Landlord shall have the. right, from time to time, and at Landlord's risk
and expense, to erect, maintain, repair and use pipes, cables, conduits and
wires in, to and through the underground or surface levels of the Project to the
extent that same may be necessary with respect to other construction or
maintenance of other property of Landlord adjoining or proximately related to
the Project. All such work shall be done in such manner and at such times as to
avoid undue interference with Tenant's use and enjoyment of the Project.
Landlord shall promptly repair and indemnify Tenant from and against all damages
to the Project, property and any injuries to persons resulting from any such
work. All such repair work shall be performed in a good and workmanlike manner
with materials of at least the same quality as the original materials.
ARTICLE XIV
QUIET ENJOYMENT
Landlord shall, provided Tenant pays all Rent and fulfills all terms and
conditions of this Lease, take all necessary steps to secure to Tenant and to
maintain for the benefit of Tenant, subject to the provisions hereof, the quiet
and peaceful possession of the Project for the Term, without hindrance by
Landlord or any other person claiming or purporting to claim
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title to the Project for the Term, or any part thereof, by, through or under
Landlord. It is acknowledged by Tenant that the Premises are subject to alleged
claims for payment of mechanics and materialmen as evidenced by Affidavit for
Fixing Lien filed December 10, 1984, in the amount of $25,759.92 recorded in the
Official Public Records of Galveston County, Texas, under Film Code No.
###-##-####. Landlord hereby affirmatively covenants to Tenant that the claims
represented by such Affidavit for Fixing Lien do not constitute an exception to
the warranty provided above. Landlord specifically agrees to indemnify and hold
Tenant and any parties claiming by, through or under Tenant harmless from and
against any and all loss, cost, expense, damage, liability, demand, claim,
action or cause of action (including but not limited to reasonable attorneys'
fees) arising from, related to or in any way caused by such claim. Landlord
shall immediately take affirmative action to contest and resolve such claim and
diligently pursue prosecution thereof in order that such claim may be released.
In the event such claim has an adverse material effect on Tenant or Tenant's
Plant, Landlord shall cause such claim to be removed against the Premises within
sixty (60) days after written demand therefor by Tenant.
ARTICLE XV
HOLDING OVER
In the event Tenant holds over after expiration or termination of
this Lease, and any extension or renewal thereof, without the written consent of
Landlord, Tenant shall pay as Rent one hundred twenty-five percent (125%) of the
Rent effective immediately prior to the commencement of the holdover period. No
holding over by Tenant after the Term shall operate to extend the Lease. In the
event of any unauthorized holding over, Tenant shall indemnify Landlord against
all claims for damages, including, but not limited to, claims by any other
lessee to whom Landlord may have leased the Project, or a portion thereof,
effective upon the termination of this Lease. Any holding over with the consent
of Landlord in writing shall thereafter constitute this Lease a lease from month
to month.
ARTICLE XVI
NOTICES
Any notices or communications permitted or required by this Lease to
be in writing shall be deemed sufficiently given if delivered in person or sent
by United States Postal Service, certified mail, postage prepaid, return receipt
requested addressed to the respective parties at the following addresses:
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If to Landlord: Union Carbide Corporation
P. O. Box 471
Texas City, Texas 77590
Attention: Energy Systems Manager
with a copy to: Corporate Real Estate Department
Union Carbide Corporation
Old Ridgebury Road
Danbury, Connecticut 06817
If to Tenant: Northern Cogeneration One Company
2600 Dodge Street
Omaha, Nebraska 68131
Attention: Vice President and
General Manager, Cogeneration
Business Line
Any such notices or communication shall be deemed to have been given
as of the date so delivered or mailed as evidenced by the stamped postal
receipt. Either party hereto may change its address for the foregoing purposes
by giving written notice as provided hereunder of its new address.
ARTICLE XVII
GENERAL PROVISIONS
17.01 Time is of the Essence. In all instances where Tenant is
required hereunder to pay any sum or to perform any act at a particular
indicated time or within an indicated period, time is of the essence of such
provision.
17.02 Entire Agreement. This Lease, together with other related
contracts and documents provided in connection therewith, contains the entire
agreement of the parties, and no representations or agreements, oral or
otherwise, between the parties which are not embodied therein or attached
thereto shall be of any force or effect. Any additions or amendments to this
Lease will be of no force or effect unless in writing and signed by the parties
hereto.
17.03 No Agency or Partnership. Nothing herein will be deemed or
construed by the parties hereto, nor by any third party, as creating or
authorizing the creation of the relationship of principal and agent or of a
partnership or joint venture between Landlord and Tenant.
17.04 No Merger. There will be no merger of this Lease or of the
leasehold estate created hereby with the fee estate in the Premises or any
portion thereof by reason of the fact that the same person or entity may acquire
or hold, directly
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or indirectly, all or part of such Lease or leasehold estate, or any interest
therein, and such fee estate, or any interest therein.
17.05 Attorneys' Fees. In the event of any litigation regarding this
Lease, the losing party shall pay to the prevailing party all reasonable
attorneys' fees in connection with such proceedings.
17.06 Governing Law. This Lease will be governed and construed in
accordance with the laws of the State of Texas. Venue of any suit, right or
cause of action arising under or in connection with this Lease shall lie
exclusively in Galveston County, Texas.
17.07 Partial Invalidity. If any term or provision of this Lease or
the application thereof to any person or circumstances will, to any extent, be
illegal, invalid or unenforceable under Applicable Law or becomes unenforceable
because of judicial construction, the remaining terms and provisions of this
Lease or the application thereof to persons or circumstances other than those as
to which it is held unenforceable shall not be affected thereby.
17.08 Binding Effect. The terms and conditions of this Lease
constitute a real property right and covenant running with the Premises and
shall be binding upon and inure to the benefit of the parties hereto, their
respective legal representatives, successors and assigns. Notwithstanding
termination of this Lease, the obligations of the respective parties hereto
arising prior to such termination shall continue and remain in full force and
effect.
17.09 Construction. The headings contained in this Lease are for
reference purposes only and shall not affect the meaning or interpretation of
this Lease. All personal pronouns used in this Lease include the other genders,
whether used in the masculine, feminine or neuter gender, and the singular shall
include the plural whenever and as often as may be appropriate.
17.10 Memorandum of Lease. At the request of either party hereto,
Landlord and Tenant shall execute an appropriate memorandum of this Lease in
recordable form for filing in the Official Records of Real Property for
Galveston County, Texas.
17.11 Confidentiality Except to the extent necessary to record a
sufficient memorandum of this Lease as provided in Section 17.10 hereof, the
parties agree that the terms and conditions contained in this Lease shall not be
disclosed to third parties without the written consent of the parties hereto;
provided, however, that the terms and conditions in this Lease may
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be disclosed to the extent such disclosure is required to comply with an order
of a court or administrative body having jurisdiction over this Lease.
17.12 Force Majeure. Neither Landlord or Tenant shall be liable to
the other for failure to perform as required in this Lease or for any damages
resulting from such failure to the extent that such failure or damages shall be
the result of occurrences of Force Majeure.
17.13 Compliance with Laws. Landlord and Tenant shall at all times
comply with all applicable and properly enacted statutes, ordinances, codes,
regulations, or enactments of public bodies or Governmental Authorities
exercising jurisdiction over the subject matter hereof in the installation and
operation of all facilities and equipment, and any other performance, required
hereunder. Tenant shall be solely responsible for acquiring any permits,
certificates or other such governmental approvals required by Applicable Law for
the construction and provision of Tenant's Plant and the Retrofit Equipment,
except to the extent otherwise expressly provided in the Agreements or agreed by
Landlord in writing.
17.14 Late Payments. (a) Each party hereto acknowledges that late
payment of any sum due hereunder will cause the receiving party to incur costs
not contemplated by this Lease, the exact amount of which will be difficult to
ascertain. Accordingly, if any sum due under this Lease shall not be received
within twenty (20) days after the same is due and payable, then the obligor
shall pay the sum due plus the Applicable Rate applied on a per annum basis, and
any costs of collection incurred by the party to be paid by reason of failure to
pay when due. Acceptance of late payments shall in no event constitute a waiver
of any default with respect to such overdue amount, nor prevent any party from
exercising any other rights and remedies granted herein.
(b) If Tenant fails to pay in full any installment or payment of
Rent or other charge or money obligation herein required to be paid by Tenant
within a period of ninety (90) days after such payment is due, unless Tenant
shall in good faith be disputing the portion of the amount due that has not been
paid, Landlord may offset the amount of such Rent or other charge or money
obligation against any amounts owed by Landlord to Tenant under the Steam and
Electricity Service Agreement.
17.15 Precautionary Filings. Landlord and Tenant intend that this
instrument shall be an agreement of lease and such instrument shall not be
intended as a security device. The parties hereto intend to file a Form UCC-1
Financing Statement in accordance with the provisions of Section 9.408 of the
Texas
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Business and Commerce Code, which Financing Statement shall designate the
parties hereto as Landlord and Tenant, it being such parties' intent that such
Financing Statement shall not of itself be a factor in determining whether or
not this Lease is intended as security.
17.16 Priority of Agreements. In the event of any inconsistency
between or among this Lease, the Stream and Electricity Service Agreement or the
Utility Service Agreement, or any other agreements or documents prepared in
connection therewith, the order of priority of such agreements shall be as
follows, with the controlling agreements listed first:
a) The Steam and Electricity Service Agreement.
b) The Utility Service Agreement.
c) This Lease.
d) Other agreements or documents.
17.17 Fair Market Value. (a) That party exercising its purchase
rights (the "Purchaser"), shall give written notice to the owner of the Premises
(the "Seller") specifying the name and address of an appraiser acting on its
behalf to appraise the Premises and within twenty (20) days after receipt of
such notice the Seller shall give written notice to the Purchaser likewise
stating the name and address of its appraiser for such purposes. Said appraiser
shall within twenty (20) days after appointment of Seller's appraiser, appoint a
mutually acceptable third appraiser. Each of the said appraisers shall be a
member of the American Institute of Real Estate Appraisers or the Society of
Real Estate Appraisers and shall be reasonably qualified by professional
training and practical experience to appraise industrial real estate situated in
Galveston County, Texas.
(b) Each of said three appraisers shall promptly and independently
endeavor to arrived at the fair market value of the Premises based upon its use
for industrial activity and based upon such additional matters as are
customarily taken into account in preparing such appraisals. Each appraiser
shall submit to Seller and Purchaser a written appraisal report. The average
value of the two appraisals having values nearest to each other shall be the
fair market value of the Premises. Said appraisals shall be submitted to Seller
and Purchaser no later than thirty (30) days after the appointment of the third
appraiser.
(c) In the event that the two appraisers appointed by Seller and
Purchaser shall fail to appoint a third appraiser within the aforesaid twenty
(20) day period following appointment
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appraisals shall be submitted to Landlord and Tenant no later than thirty (30)
days after the appointment of the third appraiser.
(c) In the event that the two appraisers appointed by Landlord and
Tenant shall fail to appoint a third appraiser within the aforesaid twenty (20)
day period following appointment of second appraiser, then the third appraiser
shall be designated by the American Arbitration Association in the City of
Houston, Texas upon the request of either of the parties hereto.
(d) Each party shall pay the fees and expenses of the appraiser
designated by it, and the parties shall share equally the fees and expenses of
the third appraiser.
EXECUTED AND WRITTEN effective as of the date and year first above
written.
LANDLORD:
UNION CARBIDE CORPORATION
By: /s/ H. W. Lichtenberger
--------------------------------------
ATTEST: Name: /s/ H. W. Lichtenberger
-------------------------------
[SIG] Title: President
- --------------------------- -------------------------------
Solvents & Coatings Material
TENANT:
NORTHERN COGENERATION ONE COMPANY
ATTEST: By: /s/ Gary D. Hoover
--------------------------------------
/s/ J. M. Bligh Name: Gary D. Hoover
- ----------------------------- -------------------------------
Assistant Secretary Title: Vice Pres & Gen Mngr.
-------------------------------
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<PAGE> 36
EXHIBIT "A"
A TRACT OF LAND OUT-OF KOHFELDT'S SECOND ADDITION TO THE CITY OF TEXAS
CITY, GALVESTON COUNTY, TEXAS
According to the map of Kohfeldt's Second Addition to the City of Texas City of
record in Volume 254-A, Page 19 in the office of the County Clerk of Galveston
County, Texas and being more fully described by metes and bounds as follows:
BEGINNING at a one-inch iron pipe set for the point of intersection of the South
right-of-way line of 5th Avenue South and and the West right-of-way line of
Grant Street, said beginning point being the Northeast corner of Block 2 of said
Kohfeldt's Second Addition and having 29 degrees 22' 40" North Latitude and 94
degrees 56' 34.8" West Longitude based on U.S.C.G.S. Horizontal Control
Monuments;
THENCE South 0 degrees 01' 12" East along the West right-of-way line of Grant
Street, same being the East line of said Block 2, a distance of 418.78 feet to a
one-inch iron pipe set for corner;
THENCE South 89 degrees 581 48" West along a line parallel to the South line of
said Block 2 a distance of 960.57 feet to a one-inch iron pipe set for corner;
THENCE North 0 degrees 01' 12" West along a line parallel to the East line of
said Block 2 a distance of 406.19 feet to a one-inch iron pipe set for corner on
the South right-of-way line of 5th Avenue South;
THENCE North 89 degrees 15' 07" East along the South right-of-way line of 5th
Avenue South a distance of 300.65 feet to a one-inch iron pipe set for point of
intersection;
THENCE North 89 degrees 13' 07" East along the South right-of-way line of 5th
Avenue South a distance of 660.00 feet to the PLACE OF BEGINNING and containing
9.09 Acres of land, more or less;
SUBJECT TO the pipeline facilities described on the attached Exhibit C and a
multi-pipeline easement shown on D. Engineers Inc. Plat dated September 30, 1985
as shown on the attached Exhibit A-1.
<PAGE> 37
EXHIBIT "C"
Map describing Diagram of 24" Outfall Pipe Location Plan
<PAGE> 1
Exhibit: 10.11.3
================================================================================
STOCK PURCHASE AGREEMENT
AMONG
GAS ENERGY INC.,
GAS ENERGY COGENERATION INC.,
THE BROOKLYN UNION GAS COMPANY,
CALPINE EASTERN CORPORATION
AND
CALPINE CORPORATION
DATED: AUGUST 22, 1997
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Introduction......................................................................... 1
ARTICLE I
PURCHASE AND SALE OF STOCK
1.1. Purchase and Sale ............................................................... 1
1.2. Purchase Price and Adjustments .................................................. 1
1.3. Closing ......................................................................... 2
ARTICLE II
REPRESENTATIONS AND WARRANTIES
2.1. Representations and Warranties Relating to the Seller ........................... 2
(a) Title to Shares ................................................................. 3
(b) Organization and Standing of the Seller ......................................... 3
(c) Authority; Binding Agreement .................................................... 3
(d) Conflicts; Consents ............................................................. 3
(e) Brokers ......................................................................... 3
2.2. Representations and Warranties Relating to the Companies, the
Subsidiaries and the Partnerships ............................................... 4
(a) Organization, Standing and Power ................................................ 4
(b) Authority; Binding Agreement .................................................... 5
(c) Capitalization; Equity Interests ................................................ 5
(d) Conflicts; Consents ............................................................. 6
(e) Financial Information ........................................................... 7
(f) Absence of Changes .............................................................. 8
(g) Tax Matters ..................................................................... 11
(h) Assets, Property and Related Matters ............................................ 11
(i) Patents, Trademarks and Similar Rights .......................................... 12
(j) Insurance ....................................................................... 12
(k) Agreements, Etc ................................................................. 12
(l) Litigation, Etc ................................................................. 13
(m) Compliance; Governmental Authorizations ......................................... 13
(n) Labor Relations; Employees ...................................................... 14
(o) Related Party Transactions ...................................................... 15
(p) Utility Regulation .............................................................. 15
(q) Investment Company Act .......................................................... 15
2.3. Representations and Warranties by the Purchaser ................................. 16
(a) Organization, Standing and Power ................................................ 16
(b) Authority; Binding Agreement .................................................... 16
(c) Conflicts; Consents ............................................................. 17
</TABLE>
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<TABLE>
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(d) Regulatory Status ............................................................... 14
(e) Brokers ......................................................................... 14
(f) Investment Representations ...................................................... 17
(g) Seller's Representations and Warranties ......................................... 15
ARTICLE III
ADDITIONAL AGREEMENTS
3.1. Expenses, Taxes ................................................................. 15
3.2. Conduct of Business ............................................................. 18
3.3. Further Assurances .............................................................. 18
3.4. Access and Information .......................................................... 16
3.5. Public Announcements ............................................................ 19
3.6. Taxes ........................................................................... 19
3.7. Employees of the Companies ...................................................... 17
3.8. Divestiture of Certain Assets and Subsidiaries .................................. 17
3.9. PUT RIGHT ....................................................................... 20
3.10. Corporate Name Change ........................................................... 21
ARTICLE IV
CLOSING CONDITIONS
4.1. Conditions of Obligations of the Purchaser ...................................... 21
(a) Representations and Warranties .................................................. 18
(b) Certificates .................................................................... 18
(c) Consents and Waivers ............................................................ 18
(d) Opinions of Counsel ............................................................. 22
(e) Joint Litigants' Agreement ...................................................... 22
(f) Share Certificates and Corporate Records ........................................ 22
(G) LEGAL BAR ....................................................................... 23
(H) RESIGNATIONS .................................................................... 18
(I) AMENDMENT OF TBG BALANCING AGREEMENT ............................................ 18
(J) ALLOCATION ...................................................................... 23
(K) AGREEMENTS ...................................................................... 23
4.2. Conditions of Obligations of the Seller ......................................... 23
(a) Representations and Warranties .................................................. 23
(b) Certificate ..................................................................... 23
(c) Consents and Waivers ............................................................ 23
(d) Opinion of Counsel .............................................................. 24
(e) Joint Litigants' Agreement ...................................................... 24
(f) Purchase Price .................................................................. 24
(g) LEGAL BAR ....................................................................... 24
(h) AMENDMENT OF TBG BALANCING AGREEMENT ............................................ 24
(i) ALLOCATION ...................................................................... 24
</TABLE>
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ARTICLE V
INDEMNITY
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5.1. GENERAL ......................................................................... 25
5.2. KIAC Construction Disputes ...................................................... 25
5.3. Notices ......................................................................... 27
5.4. Insurance and Tax Benefits ...................................................... 27
ARTICLE VI
MISCELLANEOUS
6.1. Entire Agreement ................................................................ 27
6.2. Aggregate Liability ............................................................. 27
6.3. Termination ..................................................................... 27
6.4. Descriptive Headings; Certain Interpretations ................................... 28
6.5. Notices ......................................................................... 29
6.6. Counterparts .................................................................... 32
6.7. Survival ........................................................................ 32
6.8. Benefits of Agreement ........................................................... 32
6.9. Amendments and Waivers .......................................................... 32
6.10. Assignment ...................................................................... 33
6.11. Guarantee ....................................................................... 33
6.12. Governing Law .................................................................. 33
6.13. Consent to Jurisdiction ........................................................ 33
</TABLE>
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<PAGE> 5
Schedules
1.2 Sample Net Working Capital Statement
2.2(a)-1 Current Subsidiaries
2.2(a)-2 Subsidiaries
2.2(a)-3 Partnerships; GEI Partnership Interests and Partnership Agreements
2.2(a)-4 Materials Claims on GEI Partnership Interests
2.2(c)-1 Agreements Relating to the Shares
2.2(c)-2 Other Partnership Interests
2.2(c)-3 Capital Contributions
2.2(c)-4 Outstanding Guarantees
2.2(d)-1 Waivers and Consents
2.2(d)-2 Governmental Approvals
2.2(e) Financial Statements
2.2(f) Absence of Changes
2.2(g) Tax Matters
2.2(h)-1 Material Claims
2.2(h)-2 Real Property
2.2(h)-3 Personal Property
2.2(j) Insurance
2.2(k)-1 Certain Agreements
2.2(k)-2 Defaults
2.2(l)-1 Litigation
2.2(l)-2 Judgments
2.2(m)-1 Governmental Compliance
2.2(m)-2 Exceptions to Licenses and Permits
2.2(m)-3 Licenses and Permits
2.2(n)-1 Labor Relations
2.2(n)-2 Employee Plans
2.2(o) Related Party Transactions
2.2(p) Utility Regulation
3.8-1 Divested Assets
3.8-2 Assumed Liabilities
5.2(a) KIAC Construction Contracts
iv
<PAGE> 6
Exhibits
A Form of Joint Litigants' Agreement
B-1 Form of Opinion of Cullen and Dykman (with respect to The Brooklyn Union
Gas Company)
B-2 Form of Opinion of Cullen and Dykman (with respect to Gas Energy Inc.
and Gas Energy Cogeneration Inc.)
B-3 Form of Opinion of Howard, Darby & Levin
C-1 Form of Opinion of Joseph E. Ronan, Jr., Esq.
C-2 Form of Opinion of Washburn, Briscoe & McCarthy
v
<PAGE> 7
STOCK PURCHASE AGREEMENT, dated August 22, 1997, among Gas Energy
Inc., a New York corporation ("GEI"), Gas Energy Cogeneration Inc., a Delaware
corporation ("GECI," and together with GEI, the "Companies"), The Brooklyn Union
Gas Company, a New York corporation (the "Seller"), Calpine Eastern Corporation,
a Delaware corporation (the "Purchaser"), and Calpine Corporation, a Delaware
corporation (the "Guarantor").
Introduction
The Seller owns all of the issued and outstanding shares of
capital stock of each of the Companies (the "Shares"). Subject to the terms and
conditions of this Agreement, the Seller desires to sell to the Purchaser, and
the Purchaser desires to purchase from the Seller, all of the Shares.
In consideration of the mutual benefits to be derived from this
Agreement and of the representations, warranties, conditions, agreements and
promises contained herein and other good and valuable consideration, the parties
agree as follows:
ARTICLE I
PURCHASE AND SALE OF STOCK
1.1. Purchase and Sale. Subject to the terms and conditions set
forth herein, on the Closing Date (as defined in Section 1.3), the Seller shall
sell and deliver to the Purchaser all of the Shares and the Purchaser shall
purchase the Shares from the Seller.
1.2. Purchase Price and Adjustments. (a) The purchase price (the
"Purchase Price") for the Shares shall be cash in the amount of $102,500,000 (of
which $102,400,000 shall be consideration for the Shares and $100,000 shall be
consideration for the put option set forth in Section 3.9), subject to
adjustment in accordance with paragraph (b) below and subject to further
adjustment pursuant to Section 4.1(c) and (i) and Section 4.2(c) and (h),
payable by wire transfer in immediately available funds, to one or more bank
accounts of the Seller. Such bank accounts shall be designated by the Seller in
writing not later than two business days prior to the Closing Date.
(b) (i) Within ten business days after the Closing Date, the
Seller shall deliver to the Purchaser a statement (the "Net Working Capital
Statement") setting forth the Net Working Capital of the Companies as of the
<PAGE> 8
earlier of (x) the Closing Date and (y) September 30, 1997 (the "Final Net
Working Capital"), prepared by a Vice President of the Seller. The Net Working
Capital Statement shall be subject to the review and approval of the Purchaser
within 15 business days of receipt thereof. The Seller and its representatives
and agents shall have access to the Companies and the Subsidiaries (as defined
in Section 2.2(a)(ii)) and their respective officers, counsel, auditors, books
and records to verify the amounts set forth in the Net Working Capital
Statement. As used in this Section 1.2, "Net Working Capital" means the excess
of (i) the sum of the Companies' (A) cash and cash equivalents, (B) receivables
(trade and affiliated partnership), (C) oil inventory, (D) advances (on behalf
of TBG Cogen Partners) and (E) prepayments over (ii) the sum of the Companies'
(A) accounts payable and accrued liabilities (third party and parent company)
and (B) secured loans; provided, however, that, except as set forth in Section
5.2(b), the amounts described in items (A) and (B) of clause (i) shall not
include any cash or cash equivalents resulting from, or any receivables related
to, any distributions made or declared by any of the Partnerships (as defined in
Section 2.2(a)(iii)) in respect of the GEI Partnership Interests (as defined in
Section 2.2(a)(iii)) on or after July 1, 1997, and such cash, cash equivalents
and receivables shall not be included in the calculation of Net Working Capital.
(ii) The Net Working Capital Statement shall be prepared in
accordance with generally accepted accounting principles applied on a basis
consistent with the Companies' balance sheet at September 30, 1996 included as
part of Schedule 2.2(e). A sample Net Working Capital Statement is set forth on
Schedule 1.2.
(iii) If the Final Net Working Capital as set forth in the Net
Working Capital Statement exceeds zero dollars (the "Base Net Working Capital"),
the Purchase Price shall be increased by the amount of such excess and the
Purchaser shall, within five business days of approval by the Purchaser of the
Net Working Capital Statement, pay to the Seller an amount equal to such excess
by wire transfer in immediately available funds to an account designated by the
Seller for that purpose. If the Base Net Working Capital exceeds the Final Net
Working Capital as set forth in the Final Net Working Capital Statement, the
Purchase Price shall be decreased by the amount of such excess and the Seller
shall, within five business days of approval by the Purchaser of the Net Working
Capital Statement, pay to the Purchaser an amount equal to such excess by wire
transfer in immediately available funds to an account designated by the
Purchaser for that purpose.
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1.3. Closing. The closing (the "Closing") for the consummation of
the transactions contemplated by this Agreement shall take place at the offices
of Howard, Darby & Levin, 1330 Avenue of the Americas, New York, New York 10019,
or such other place as the Seller and the Purchaser shall agree, at 10:00 a.m.
(New York City time) on the later of September 30, 1997 and the date on which
all conditions set forth in Article IV shall have been satisfied or waived, or
such other date and time agreed to by the Seller and the Purchaser (such date of
the Closing being herein called the "Closing Date").
ARTICLE II
REPRESENTATIONS AND WARRANTIES
2.1. Representations and Warranties Relating to the Seller. The
Seller represents and warrants to the Purchaser as follows:
(a) Title to Shares. The Seller is the lawful owner, of record
and beneficially, of the Shares and has, and will transfer to the Purchaser at
the Closing, good and marketable title to the Shares, free and clear of all
security interests, liens, pledges, charges, escrows, options, rights of first
refusal, mortgages, indentures, security agreements or other encumbrances (each,
a "Claim," and collectively, "Claims"), and with no restriction on, or agreement
relating to, the voting rights and the other incidents of record and beneficial
ownership pertaining to the Shares.
(b) Organization and Standing of the Seller. The Seller is a
corporation duly organized, validly existing and in good standing under the laws
of the State of New York.
(c) Authority; Binding Agreement. The Seller has full corporate
power and authority to execute and deliver this Agreement and the Joint
Litigants' Agreement, in substantially the form of Exhibit A (the "Joint
Litigants' Agreement"), and to perform its obligations hereunder and thereunder.
This Agreement has been duly authorized, executed and delivered by the Seller
and is the valid and binding obligation of the Seller, enforceable against the
Seller in accordance with its terms, subject to bankruptcy, insolvency,
fraudulent transfer, reorganization, moratorium and other laws of general
applicability relating to or affecting creditors' rights and to general equity
principles. The Joint Litigants' Agreement has been duly authorized by the
Seller, and, upon the Seller's due execution and delivery thereof, will be
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<PAGE> 10
the valid and binding obligation of the Seller, enforceable against the Seller
in accordance with its terms, subject to bankruptcy, insolvency, fraudulent
transfer, reorganization, moratorium and other laws of general applicability
relating to or affecting creditors' rights and to general equity principles.
(d) Conflicts; Consents. Neither the execution and delivery of
this Agreement or the Joint Litigants' Agreement, the consummation of the
transactions contemplated hereby or thereby nor compliance by the Seller with
any of the provisions hereof or thereof will (i) conflict with or result in a
breach of the charter, by-laws or other constitutive documents of the Seller,
(ii) conflict with or result in a default (or give rise to any right of
termination, cancellation or acceleration) under any of the provisions of any
material agreement binding upon the Seller, or (iii) violate any law or statute
or, to the knowledge of the Seller, any rule or regulation or order, writ,
injunction or decree applicable to the Seller or the Seller's properties or
assets. Except for compliance with any applicable requirements under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the "HSR Act") and except
as set forth in Schedule 2.2(d)-2, no consent or approval by, or any
notification of or filing with, any governmental authority or body is required
in connection with the execution, delivery and performance by the Seller of this
Agreement or the Joint Litigants' Agreement or the consummation of the
transactions contemplated hereby or thereby.
(e) Brokers. No agent, broker, investment banker or any other
person, firm, corporation, partnership, joint venture, association or other
entity (governmental or private) (each, a "Person" and collectively, "Persons")
acting on behalf of the Seller or under the authority of the Seller is or will
be entitled to any broker's or finder's fee or any other commission or similar
fee directly or indirectly from any of the parties hereto in connection with any
of the transactions contemplated hereby, except for Donaldson, Lufkin & Jenrette
Securities Corporation ("DLJ").
2.2. Representations and Warranties Relating to the Companies,
the Subsidiaries and the Partnerships. Subject to Section 6.4, the Seller
represents and warrants to the Purchaser as follows:
(a) Organization, Standing and Power. (i) GEI is a corporation
duly organized, validly existing and in good standing under the laws of the
State of New York, and GECI is a corporation duly organized, validly existing
and in good standing under the laws of the State of Delaware. Each of the
Companies has all requisite corporate power and authority to own, lease and
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<PAGE> 11
operate its properties and to carry on its business as now being conducted and
is duly qualified to do business and is in good standing in the State of New
York and in each other jurisdiction in which such qualification is necessary
because of the property owned, leased or operated by it or because of the nature
of its business as now being conducted, except in those jurisdictions where the
failure to be so qualified would not have a material adverse effect on the
financial condition, business or results of operations of the Companies and the
Subsidiaries, individually or taken as a whole (a "Material Adverse Effect").
(ii) Schedule 2.2(a)-1 hereto contains a true and complete
list of all corporations or limited liability companies of which either of the
Companies owns, directly or indirectly, any shares of capital stock or member
interests together with a description of the type and amount of such capital
stock or interests outstanding on the date hereof. Schedule 2.2(a)-2 hereto
contains a list of all such corporations and limited liability companies other
than corporations to be divested on or before the Closing Date and listed on
Schedule 3.8-1 hereto (all such corporations and limited liability companies
listed on Schedule 2.2(a)-2, the "Subsidiaries"). Each of the Subsidiaries is a
corporation duly organized, validly existing and in good standing under the laws
of the jurisdiction of its incorporation. Each of the Subsidiaries has all
requisite corporate power and authority to own, lease and operate its properties
and to carry on its business as now being conducted and is duly qualified to do
business and is in good standing in the State of New York and in each other
jurisdiction in which such qualification is necessary because of the property
owned, leased or operated by it or because of the nature of its business as now
being conducted, except in those jurisdictions where the failure to be so
qualified would not have a Material Adverse Effect. All of the outstanding
capital stock of the Subsidiaries (the "Subsidiaries' Shares") have been validly
issued and are fully paid and nonassessable and are owned, of record and
beneficially, by either of the Companies, one of the other Subsidiaries, or any
combination thereof, free and clear of any Claim material to the financial
condition, business or results of operations of the Companies and the
Subsidiaries, individually or taken as a whole (a "Material Claim").
(iii) Schedule 2.2(a)-3 hereto contains a true and
complete list of all partnerships in which the Subsidiaries own, directly and
indirectly, any partnership interests (the "Partnerships"), together with a
description of the type and amount of such interest (the "GEI Partnership
Interests"), and the owners thereof, and a list of all joint venture or
partnership agreements pursuant to which the Partnerships were formed and all
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<PAGE> 12
other written agreements between or among any of the Subsidiaries and the
partners in the Partnerships in their capacity as partners (collectively, the
"Partnership Agreements"). The Companies have provided the Purchaser with access
to true and correct copies of the Partnership Agreements. Each of KIAC Partners,
EnergyPro Construction Partners, Nissequogue Cogen Partners and TBG Cogen
Partners (collectively, the "General Partnerships") and, to the knowledge of the
Seller, Lockport Energy Associates, L.P. ("Lockport"), is a partnership duly
organized and validly existing under the laws of the jurisdiction of its
organization and has all requisite partnership power and authority to own, lease
and operate its properties and to carry on its business as now being conducted.
The GEI Partnership Interests are owned, of record and beneficially, by one or
more of the Subsidiaries and, except as set forth on Schedule 2.2(a)-4, are free
and clear of any Material Claim.
(iv) Except for the Subsidiaries' Shares, shares of capital stock
of the corporations listed on Schedule 3.8-1 and the GEI Partnership Interests,
neither of the Companies nor any Subsidiary owns, directly or indirectly, any
shares of capital stock or securities convertible into capital stock of, or any
partnership or other equity interest in, any Person.
(b) Authority; Binding Agreement. Each of the Companies has full
corporate power and authority to execute and deliver this Agreement and to
perform its obligations hereunder. This Agreement has been duly authorized,
executed and delivered by each of the Companies and is the valid and binding
obligation of the Companies, enforceable against the Companies in accordance
with its terms, subject to bankruptcy, insolvency, fraudulent transfer,
reorganization, moratorium and other laws of general applicability relating to
or affecting creditors' rights and to general equity principles.
(c) Capitalization; Equity Interests. (i) Except for the Shares
and the Subsidiaries' Shares, there are no other shares of capital or other
equity securities of either of the Companies or any of the Subsidiaries issued
or outstanding. All of the Shares and the Subsidiaries' Shares are validly
issued and outstanding, fully paid and nonassessable. No Person is entitled to
any preemptive or similar rights with respect to the Shares or the Subsidiaries'
Shares. There are no rights to acquire or options, warrants, call agreements,
convertible securities or other commitments to issue, exchange or acquire,
directly or indirectly, any unissued or treasury shares of capital stock or
other securities of either of the Companies or any of the Subsidiaries, and no
other securities of either of the Companies or any of the Subsidiaries are
reserved for issuance for any purpose. Except as set forth on
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<PAGE> 13
Schedule 2.2(c)-1, there are no agreements to which the Seller or either of the
Companies or any of the Subsidiaries is a party or by which the Seller, either
of the Companies or any of the Subsidiaries is bound relating to the Shares or
any shares of capital stock or other securities or equity interests of either of
the Companies or any of the Subsidiaries, whether or not outstanding.
(ii) To the knowledge of the Seller, Schedule 2.2(c)-2
sets forth a true and complete list of all Persons other than the Subsidiaries
that own any partnership interest in any of the Partnerships, together with a
description of the type and amount of such interest (the "Other Partnership
Interests"). To the knowledge of the Seller, other than the GEI Partnership
Interests and the Other Partnership Interests, there are no outstanding
partnership or other equity interests in any Partnership. The GEI Partnership
Interests in the General Partnerships and, to the knowledge of the Seller, in
Lockport, have been validly created and are validly existing and outstanding
pursuant to applicable law and agreement (including the applicable Partnership
Agreements). Except as set forth in Schedule 2.2(c)-3, all capital
contributions, loans and other advances that are required to have been made by
either of the Companies or any Subsidiary to or on behalf of any Partnership on
or before the date hereof under any applicable contract, agreement or other
instrument listed on Schedule 2.2(k) have been indefeasibly made in full, and
neither of the Companies has any current obligation to make a capital
contribution, loan or other advance to or on behalf of any Partnership under any
such contract, agreement or other instrument. No Person holds any outstanding
rights to acquire or options, warrants, call agreements, convertible securities
or other commitments to issue, exchange or acquire, directly or indirectly, any
unissued partnership interests in any of the General Partnerships or, to the
knowledge of the Seller, in Lockport. Except as set forth on Schedule 2.2(a)-3
and 2.2(k), there are no agreements to which the Seller or either of the
Companies or any of the Subsidiaries is a party or by which the Seller, either
of the Companies or any of the Subsidiaries is bound relating to the GEI
Partnership Interests or any partnership or other equity interest of any of the
Partnerships, whether or not outstanding.
(iii) Except as set forth in Schedule 2.2(c)-4, none of
the Seller, the Companies or the Subsidiaries has any outstanding obligation to
guarantee or otherwise provide credit support of any of the obligations of
either of the Companies, any of the Subsidiaries or any of the Partnerships, or
has any outstanding obligation to fund, support, guarantee or otherwise backstop
any liability or obligation, contingent or otherwise, of either of the
Companies, any of the Subsidiaries or any of the Partnerships.
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<PAGE> 14
(iv) No Subsidiary listed on Schedule 2.2(a)-2 that is a
partner in a Partnership owns any assets other than its respective GEI
Partnership Interest in such Partnership.
(v) Within the past three years, the Companies, the
Subsidiaries, the General Partnerships and, to the knowledge of the Seller,
Lockport, have not engaged in any material business activities other than those
that relate to or arise out of (A) the development, construction and operation
of the projects owned by the Partnerships, (B) the provision of fuel management
services and (C) the operations of the corporations listed on Schedule 3.8-1.
(d) Conflicts; Consents. Neither the execution and delivery of
this Agreement, the consummation of the transactions contemplated hereby nor
compliance by the Seller or either of Companies with any of the provisions
hereof will (i) conflict with or result in a breach of, or require any consent
or approval under, the charter, by-laws, Partnership Agreement or other
constitutive documents, as applicable, of either of the Companies, any of the
Subsidiaries, any of the General Partnerships or, to the knowledge of the
Seller, Lockport, except for any such conflict, breach or requirement with
respect to which requisite waivers, consents or approvals shall be obtained
before the Closing (which waivers, consents and approvals are set forth in
Schedule 2.2(d)-1), (ii) conflict with or result in a default (or give rise to
any right of termination, cancellation or acceleration), or require any consent
or approval, under any of the provisions of any contract, agreement or other
instrument referred to in Section 2.2(k) and Schedule 2.2(k), except for any
such conflict, breach, default or requirement which would not have a Material
Adverse Effect or as to which requisite waivers, consents or approvals shall be
obtained before the Closing (which waivers, consents and approvals are set forth
in Schedule 2.2(d)-1), (iii) violate any law or statute or, to the knowledge of
the Seller, any rule or regulation or order, writ, injunction or decree
applicable to either of the Companies, any of the Subsidiaries, any of the
General Partnerships or, to the knowledge of the Seller, Lockport, or the
properties or assets of the Companies, any of the Subsidiaries, any of the
General Partnerships or, to the knowledge of the Seller, Lockport, or (iv)
result in the creation or imposition of any Material Claim on the Shares, the
Subsidiaries' Shares or the GEI Partnership Interests, or on the properties or
assets of the Companies, any of the Subsidiaries, or any of the Partnerships.
Except for compliance with any applicable requirements under the HSR Act and
except as set forth in Schedule 2.2(d)-2, no consent or approval by, or any
notification of or filing with, any governmental authority or body is required
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<PAGE> 15
in connection with the execution, delivery and performance by either of the
Companies of this Agreement or the consummation of the transactions contemplated
hereby.
(e) Financial Information. The following financial statements are
attached hereto as Schedule 2.2(e) (the "Financial Statements"):
(i) The consolidated audited balance sheets of the
Companies at September 30, 1994, September 30, 1995 and September
30, 1996 and the related statements of income and cash flows for
the twelve months ended September 30, 1994, September 30, 1995
and September 30, 1996;
(ii) The consolidated unaudited balance sheet of the
Companies at June 30, 1997 and the related statements of income
and cash flows for the nine months ended June 30, 1997;
(iii) The consolidated unaudited balance sheet of the
Companies at June 30, 1997 as adjusted to eliminate the effect of
the Divested Assets (as defined in Section 3.8) and the Assumed
Liabilities (as defined in Section 3.8);
(iv) The audited balance sheets of each of the
Partnerships for their three most recent fiscal years and the
related statements of income and cash flows for the periods then
ended; and
(v) The unaudited balance sheet of each of the
Partnerships at June 30, 1997 and the related statements of
income and cash flows for the relevant period then ended.
The audited Financial Statements have been prepared in conformity with generally
accepted accounting principles applied on a basis consistent with prior periods
(except as indicated therein). The unaudited Financial Statements have been
prepared in all material respects in conformity with generally accepted
accounting principles on a basis consistent with prior periods (except that such
Financial Statements contain no notes thereto and except as otherwise
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<PAGE> 16
indicated therein). Each of the balance sheets of the Companies, the General
Partnerships and, to the knowledge of the Seller, Lockport, as at the applicable
date set forth above, presents fairly, in all material respects, the financial
position of the Companies, the General Partnerships and, to the knowledge of the
Seller, Lockport, and each of the related statements of income and cash flows
for the specified period then ended presents fairly, in all material respects,
the results of operations of the Companies, the General Partnerships and, to the
knowledge of the Seller, Lockport, for the period then ended (subject, with
respect to statements of income and cash flows relating to periods of less than
twelve months, to normal year-end audit adjustments). There were no obligations
or liabilities (whether absolute, accrued, contingent or otherwise, and whether
due or to become due) incurred by the Companies, the Subsidiaries, the General
Partnerships or, to the knowledge of the Seller, Lockport, which (x) were
required to be shown or provided for, in accordance with generally accepted
accounting principles, but were not shown or provided for, on the balance sheets
forming a part of the Financial Statements of the Companies, any of the General
Partnerships or, to the knowledge of the Seller, Lockport or (y) in the case of
unaudited Financial Statements where notes are not required, are not listed on
Schedule 2.2(f).
(f) Absence of Changes. Except as set forth in Schedule 2.2(f),
since June 30, 1997, each of the Companies, the Subsidiaries, the General
Partnerships and, to the knowledge of the Seller, Lockport, has been operated in
the ordinary course and there has not been:
(i) any obligation or liability (whether absolute,
accrued, contingent or otherwise, and whether due or to become
due) incurred by either of the Companies, any of the
Subsidiaries, any of the General Partnerships or, to the
knowledge of the Seller, Lockport, other than current obligations
and liabilities incurred in the ordinary course of business;
(ii) any payment, discharge or satisfaction of any Claim
of either of the Companies, any of the Subsidiaries, any of the
General Partnerships or, to the knowledge of the Seller,
Lockport, except in the ordinary course of business and
consistent with past practice;
(iii) any declaration, setting aside or payment of any
dividend or other distribution with respect to the
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Shares or any shares of capital stock of any of the Subsidiaries
or any distribution by any of the Partnerships with respect to
the GEI Partnership Interests, or any direct or indirect
redemption, purchase or other acquisition of any such shares or
partnership interests, or any split, subdivision or
reclassification of such shares or, to the knowledge of the
Seller, such partnership interests;
(iv) any issuance or sale, or any contract entered into
for the issuance or sale, of any shares of capital stock of
either of the Companies or any of the Subsidiaries or, to the
knowledge of the Seller, of any partnership or other equity
interests in any of the General Partnerships or, to the knowledge
of the Seller, Lockport, or securities convertible into or
exercisable for shares of capital stock of either of the
Companies or any of the Subsidiaries or for such partnership or
other equity interests in the General Partnerships or, to the
knowledge of the Seller, in Lockport;
(v) any sale, assignment, pledge, encumbrance, transfer or
other disposition of any tangible asset of either of the
Companies, any of the Subsidiaries, any of the General
Partnerships or, to the knowledge of the Seller, Lockport, or any
sale, assignment, pledge, encumbrance, transfer or other
disposition of any patents, trademarks, service marks, trade
names, copyrights, licenses, know-how or any other intangible
assets, except in each case under this clause (v), in the
ordinary course of business;
(vi) any sale, assignment, pledge, encumbrance, transfer
or other disposition of the Shares or the GEI Partnership
Interests or any right to dividends or distributions with respect
to the Shares or the GEI Partnership Interests;
(vii) any write-down of the value of any asset of either
of the Companies, any of the Subsidiaries, any of the General
Partnerships or, to the knowledge of the
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Seller, Lockport, or any write-off as uncollectible of any
accounts or notes receivable or any portion thereof, of either of
the Companies, any of the Subsidiaries, any of the General
Partnerships or, to the knowledge of the Seller, Lockport, except
to the extent such write-down or write-off is required by
generally accepted accounting principles or is consistent with
the historic accounting policies adhered to by the Companies, the
Subsidiaries or the Partnerships, as applicable;
(viii) any cancellation of any debts or claims or any
amendment, termination or waiver of any rights of value to either
of the Companies, any of the Subsidiaries, any of the General
Partnerships or, to the knowledge of the Seller, Lockport, except
in the ordinary course of business;
(ix) any capital expenditure or commitment or addition to
property, plant or equipment of (A) either of the Companies or
any of the Subsidiaries in excess of $250,000 or (B) any of the
General Partnerships or, to the knowledge of the Seller,
Lockport, in each case in excess of $500,000;
(x) any general increase in the compensation of employees
of either of the Companies or any of the Subsidiaries (including
any increase pursuant to any bonus, pension, profit-sharing or
other benefit or compensation plan, policy or arrangement or
commitment), or any increase in any such compensation or bonus
payable to any officer, shareholder, director, consultant or
agent of either of the Companies or any of the Subsidiaries
having an annual salary or remuneration in excess of $150,000;
(xi) any material damage, destruction or loss (whether or
not covered by insurance) affecting any asset or property of
either of the Companies, any of the Subsidiaries, any of the
General Partnerships or, to the knowledge of the Seller,
Lockport;
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<PAGE> 19
(xii) any change in the independent accountants of either
of the Companies, any of the Subsidiaries, any of the General
Partnerships or, to the knowledge of the Seller, Lockport, or in
the accounting methods or practices followed by the Companies,
any of the Subsidiaries, any of the General Partnerships or, to
the knowledge of the Seller, Lockport, or any change in
depreciation or amortization policies or rates followed by either
of the Companies, any of the Subsidiaries, any of the General
Partnerships or, to the knowledge of the Seller, Lockport;
(xiii) any liquidation, winding up, merger or
consolidation involving any of the Companies, the Subsidiaries or
the Partnerships;
(xiv) any commencement of any litigation by the Companies,
the Subsidiaries, the General Partnerships or, to the knowledge
of the Seller, Lockport;
(xv) any incurrence of new or additional indebtedness on
the part of the Companies, the Subsidiaries, the General
Partnerships or, to the knowledge of the Seller, Lockport, in
excess of $250,000; or
(xvi) any agreement, whether in writing or otherwise, to
take any of the actions specified in the foregoing items (i)
through (xv).
(g) Tax Matters. (i) Except as set forth on Schedule 2.2(g), all
material Federal, state, local and foreign tax returns required to be filed by
or on behalf of each of the Companies, the Subsidiaries, the General
Partnerships and, to the knowledge of the Seller, Lockport, have been filed, or
an extension has been filed with respect thereto, with the appropriate
governmental authorities or bodies in all jurisdictions in which such returns
are required to be filed. The Companies have made available to the Purchaser
true and complete copies of such returns in respect of the three most recent tax
years of the Companies, the Subsidiaries, the General Partnerships and, to the
knowledge of the Seller, Lockport. Except as set forth on Schedule 2.2(g), all
Federal, state, local and foreign income, profits, franchise, sales, use,
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occupation, property, excise and other taxes (including interest and penalties
and withholdings of tax) due from or payable by the Companies, the Subsidiaries,
the General Partnerships and, to the knowledge of the Seller, Lockport, have
been paid on a timely basis or are adequately provided for on the Financial
Statements, except for (A) any taxes which either of the Companies, any of the
Subsidiaries or any of the Partnerships is contesting in good faith and for
which adequate reserves have been established in accordance with generally
accepted accounting principles and (B) any taxes the nonpayment of which would
not have a Material Adverse Effect. The books and records maintained by the
Companies, the Subsidiaries, the General Partnerships and, to the knowledge of
the Seller, Lockport, and the balance sheets forming a part of the Financial
Statements of the Companies, the Subsidiaries, the General Partnerships and, to
the knowledge of the Seller, Lockport reflect, as of their respective dates and
subject to adjustments consistent with generally accepted accounting principles
and past practice, accrued liabilities for all taxes which are not yet due and
payable, except where the failure to do so would not have a Material Adverse
Effect. Each General Partnership and, to the knowledge of the Seller, Lockport,
has treated itself as a partnership for Federal income tax purposes in any
returns or other filings with the Internal Revenue Service (the "IRS").
(h) Assets, Property and Related Matters. The Companies and the
Subsidiaries have good title to, or a valid leasehold interest in, as
applicable, all of the assets reflected on the June 30, 1997 balance sheet that
forms a part of the Financial Statements referred to in Section 2.2(e)(ii), free
and clear of all Material Claims, except as set forth on Schedule 2.2(h)-1. Such
assets constitute all of the properties, assets, interests and rights necessary
to continue to operate the respective businesses of the Companies and the
Subsidiaries consistent with current practice. Schedule 2.2(h)-2 contains a true
and complete list of all real property owned or leased by either of the
Companies, any of the Subsidiaries, any of the General Partnerships or, to the
knowledge of the Seller, Lockport. Schedule 2.2(h)-3 contains a true and
complete list of all items of personal property owned by the Companies and the
Subsidiaries with a book value in excess of $250,000.
(i) Patents, Trademarks and Similar Rights. None of the
Companies, the Subsidiaries or, to the knowledge of the Seller, the
Partnerships, owns or uses any patents, trademarks, service marks, trade names
and copyrights, in each case registered or unregistered, inventions, software
(including documentation and object and source code listings), know-how, trade
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<PAGE> 21
secrets or other intellectual property rights which are material to the
operation of their respective businesses.
(j) Insurance. Schedule 2.2(j) contains a true and complete list
of all insurance policies held by either of the Companies, any of the
Subsidiaries, any of the General Partnerships or, to the knowledge of the
Seller, Lockport. All such policies held by the Companies, the Subsidiaries, any
of the General Partnerships and, to the knowledge of the Seller, Lockport, are
in full force and effect and all related premiums have been paid to date. To the
knowledge of the Seller, there are no pending or threatened disputes or
communications with or from any insurance carrier denying or disputing any claim
or regarding cancellation or nonrenewal of any such policy.
(k) Agreements, Etc. Schedule 2.2(k)-1 contains a true and
complete list of all written contracts, agreements and other instruments to
which either of the Companies, any of the Subsidiaries, any of the General
Partnerships or, to the knowledge of the Seller, Lockport, is a party (each in
its own name and on its own behalf) or by which any of them is bound relating to
commitments (contingent or otherwise) in excess of $250,000. Except as set forth
on Schedule 2.2(k)-2, none of the Companies, the Subsidiaries, the General
Partnerships or, to the knowledge of the Seller, Lockport, is in default under
any such contract, agreement or instrument where such default would, singly or
in the aggregate with defaults under other contracts, agreements or instruments,
have a Material Adverse Effect nor, to the knowledge of the Seller, is any party
to any such contract, agreement or instrument currently threatening or proposing
a termination thereof, where such termination would, singly or in the aggregate
with terminations under other contracts, agreements or instruments, have a
Material Adverse Effect. The Companies have provided the Purchaser with access
to a true and correct copy of each such contract, agreement and instrument. All
such contracts, agreements and instruments with the Companies, the Subsidiaries,
the General Partnerships and, to the knowledge of the Seller, Lockport, are in
full force and effect and are the valid and binding obligations of the
applicable Company, Subsidiary or General Partnership or, to the knowledge of
the Seller, Lockport, enforceable against the applicable Company, Subsidiary or
General Partnership or, to the knowledge of the Seller, Lockport, in accordance
with their respective terms, subject to bankruptcy, insolvency, fraudulent
transfer, reorganization, moratorium and other laws of general applicability
relating to or affecting creditors' rights and to general equity principles.
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(l) Litigation, Etc. Except as set forth on Schedule 2.2(l)-1,
there are no pending lawsuits, actions, claims, investigations or legal or
administrative or arbitration proceedings in respect of either of the Companies,
any of the Subsidiaries, any of the General Partnerships or, to the knowledge of
the Seller, Lockport, and, to the knowledge of the Seller, no such lawsuits,
actions, claims, investigations or proceedings are threatened, whether at law or
in equity, or before or by any Federal, state, local, foreign or other
governmental department, commission, board, bureau, agency or instrumentality,
that in any such case, if determined adversely to the Companies, the
Subsidiaries or the Partnerships would, individually or in the aggregate, have a
Material Adverse Effect. Except as set forth on Schedule 2.2(l)-2, there are no
judgments, decrees, injunctions or orders of any court, governmental department,
commission, board, bureau, agency, instrumentality or arbitrator against either
of the Companies, any of the Subsidiaries, any of the General Partnerships or,
to the knowledge of the Seller, Lockport.
(m) Compliance; Governmental Authorizations. Except as set forth
on Schedule 2.2(m)-1, each of the Companies, the Subsidiaries and, to the
knowledge of the Seller, the Partnerships is in compliance with all Federal,
state, local and foreign laws and statutes and, to the knowledge of the Seller,
rules, regulations, orders, writs, injunctions and decrees applicable to the
Companies, the Subsidiaries and the Partnerships, including laws, statutes,
rules, regulations, writs, injunctions and decrees relating to pollution,
protection of the environment or Hazardous Materials (as defined below) or any
other applicable environmental, health or safety statutes, ordinances, orders,
rules, regulations or requirements, except where the failure to comply with
which would not have a Material Adverse Effect. Except as set forth on Schedule
2.2(m)-2, each of the Companies, the Subsidiaries, the General Partnerships and,
to the knowledge of the Seller, Lockport, has all Federal, state, local and
foreign governmental licenses and permits necessary to conduct their respective
businesses as presently being conducted, except where the failure to obtain such
licenses or permits would not have a Material Adverse Effect, and each of the
Companies, the Subsidiaries and, to the knowledge of the Seller, the
Partnerships, is in compliance therewith in all material respects. All such
licenses and permits held by the Companies, the Subsidiaries, the General
Partnerships, and to the knowledge of the Seller, Lockport, are listed on
Schedule 2.2(m)-3 and are in full force and effect. The Companies, the
Subsidiaries and, to the knowledge of the Seller, the Partnerships, have
received, handled, used, stored, treated, shipped and disposed of all Hazardous
Materials in compliance in all material respects with all applicable
environmental, health and safety statutes, ordinances, orders,
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rules, regulations and requirements. There have been no unremedied releases of
Hazardous Materials by the Companies, the Subsidiaries or, to the knowledge of
the Seller, the Partnerships. None of the Companies, the Subsidiaries or, to the
knowledge of the Seller, the Partnerships has received or is aware of any claim
or notice of violations of any applicable environmental, health and safety
statutes, ordinances, orders, rules, regulations and requirements. As used
herein, "Hazardous Materials" means any substances, materials or wastes listed,
defined, designated or classified as "hazardous" or "toxic" under all applicable
environmental, health and safety statutes, ordinances, orders, rules,
regulations and requirements.
(n) Labor Relations; Employees. (i) Except as set forth on
Schedule 2.2(n)-1, within the last three years, none of the Companies, the
Subsidiaries, the General Partnerships or, to the knowledge of the Seller,
Lockport, has experienced any labor disputes with, or any work stoppages by, a
group of employees due to labor disagreements and, to the knowledge of the
Sellers, there is no such dispute or work stoppage threatened against either of
the Companies, any of the Subsidiaries or any of the Partnerships. Except as set
forth on Schedule 2.2(n)-1, none of the Companies, the Subsidiaries, the General
Partnerships or, to the knowledge of the Seller, Lockport, is a party to any
collective bargaining agreement or other contract or agreement with any labor
organization or other representative of any of their employees.
(ii) Schedule 2.2(n)-2 contains a list of each pension,
retirement, savings, deferred compensation, and profit-sharing plan and each
stock option, stock appreciation, stock purchase, performance share, bonus or
other incentive plan, severance plan, health, group insurance or other welfare
plan, or other similar plan and any "employee benefit plan" within the meaning
of Section 3(3) of the Employee Retirement Income Security Act of 1974
("ERISA"), under which either of the Companies or any of the Subsidiaries has
any current or future obligation or liability or under which any employee or
former employee (or beneficiary of any employee or former employee) of either of
the Companies or any of the Subsidiaries has or may have any current or future
right to benefits (the term "plan" shall include any contract, agreement, policy
or understanding, each such plan being hereinafter referred to individually as a
"Plan"). The Companies have caused to be delivered to the Purchaser true and
complete copies of (A) each Plan, (B) the summary plan description for each Plan
and (C) the latest annual report, if any, which has been filed with the IRS for
each Plan. Each Plan intended to be tax qualified under Sections 401(a) and
501(a) of the Internal Revenue Code of 1986, as amended (the "Code"), has been
determined by the IRS to be tax qualified under
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<PAGE> 24
such Sections and, since such determination, no amendment to or failure to amend
any such Plan adversely affects its tax qualified status. There has been no
prohibited transaction within the meaning of Section 4975 of the Code and
Section 406 of Title I of ERISA with respect to any Plan.
(iii) No Plan that is subject to Title IV of ERISA (other
than a multiemployer plan as defined in Section 4001(a)(3) of ERISA) has been
completely or partially terminated or been the subject of a reportable event (as
defined in Section 4043 of ERISA) as to which notices would be required to be
filed with the Pension Benefit Guaranty Corporation (the "PBGC") and the PBGC
has not instituted proceedings to terminate any such Plan. No termination or
withdrawal (including a partial termination or partial withdrawal) with respect
to a Plan has occurred that imposes on either of the Companies or any of the
Subsidiaries any liability to the PBGC under Title IV of ERISA.
(iv) There are no lawsuits, actions, claims,
investigations or legal or administrative or arbitration proceedings (other than
routine claims for benefits) pending or, to the knowledge of the Seller,
threatened, with respect to any Plan or the assets of any Plan that in any such
case, if determined adversely with respect to such Plan or asset, would,
individually or in the aggregate, have a Material Adverse Effect. With respect
to each Plan, all contributions (including employee salary reduction
contributions) and all material insurance premiums that have become due have
been paid, and any such expense accrued but not yet due has been properly
reflected in the Financial Statements, except where the failure to do so would
not have a Material Adverse Effect.
(o) Related Party Transactions. Except as set forth on Schedule
2.2(o), no director, officer or shareholder of either of the Companies or any of
the Subsidiaries, or any member of the immediate family of any such Person, or
any corporation, partnership, trust or other entity in which any such Person, or
any member of the immediate family of any such Person, is an officer, director,
trustee, partner or holder of more than 50% of the outstanding capital stock or
equity interest thereof, is a party to any material transaction with either of
the Companies, any of the Subsidiaries or any of the Partnerships.
(p) Utility Regulation. Except as set forth on Schedule 2.2(p),
none of the Companies, the Subsidiaries, the General Partnerships or, to the
knowledge of the Seller, Lockport, is (i) an "electric utility company", a
"holding company", or either a "subsidiary company" or an "affiliate" of a
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<PAGE> 25
"holding company" as such terms are defined in the Public Utility Holding
Company Act of 1935 ("PUHCA"), (ii) subject to regulation under PUHCA (other
than any such regulation contemplated by Section 9(a)(2), 32 or 33 of PUHCA),
(iii) subject to regulation as an "electric utility" or a "public utility" as
such terms are defined in the Federal Power Act (other than as contemplated by
18 C.F.R. ? 292.601(c) or Section 32 or 33 of PUHCA), (iv) a wholly or partially
owned subsidiary company, within the meaning of 18 C.F.R. ? 292.206 and the
decisions of the Federal Energy Regulatory Commission ("FERC") interpreting such
provision, of any of the types of entities listed in clauses (i) through (iii)
above, inclusive, or (v) subject to regulation by any state respecting the rates
of electric utilities or the financial and organizational regulation of electric
utilities as those terms are used in Section 210(e) of the Public Utility
Regulatory Policies Act of 1978 ("PURPA"), except with respect to participation
in, or ownership of, an "exempt wholesale generator" as such term is defined in
Section 32 of PUHCA. Except as set forth on Schedule 2.2(p), not more than 50%
of the ultimate ownership of the project operated by each General Partnership
and, to the knowledge of the Seller, Lockport, is held by Persons primarily
engaged in the generation or sale of electric power (other than electric power
solely from qualifying cogeneration facilities, qualifying small power
production facilities, exempt wholesale generators or foreign utilities
companies (as defined in Section 33 of PUHCA)) within the meaning of the Federal
Power Act. Each such project has self- certified itself to be in compliance with
such requirements without objection by FERC or FERC has issued a final order
stating that each such project is a facility which complies with the definition
of "cogeneration facility" as set forth in 18 C.F.R. ? 292.202(c) and which
meets all of the requirements for qualification set forth in 18 C.F.R. ?
292.203(b).
(q) Investment Company Act. None of the Companies, the
Subsidiaries, the General Partnerships or, to the knowledge of the Seller,
Lockport, is an "investment company" or a company "controlled" by an investment
company within the meaning of the Investment Company Act of 1940.
2.3. Representations and Warranties by the Purchaser. Each of the
Purchaser and the Guarantor, jointly and severally, represents and warrants to
the Seller as follows:
(a) Organization, Standing and Power. Each of the Purchaser and
the Guarantor is a corporation duly organized, validly existing and in good
standing under the laws of Delaware, has all requisite corporate power and
authority to own, lease and operate its properties and to carry on its business
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as now being conducted, and is duly qualified to do business and is in good
standing in each jurisdiction in which such qualification is necessary because
of the property owned, leased or operated by it or because of the nature of its
business as now being conducted, except in those jurisdictions where the failure
to be so qualified would not have a material adverse effect on the Purchaser or
the Guarantor.
(b) Authority; Binding Agreement. Each of the Purchaser and the
Guarantor has full corporate power and authority to execute and deliver this
Agreement and the Joint Litigants' Agreement and to perform its obligations
hereunder and thereunder. This Agreement has been duly authorized, executed and
delivered by each of the Purchaser and the Guarantor and is the valid and
binding obligation of each of the Purchaser and the Guarantor, enforceable
against the Purchaser and the Guarantor in accordance with its terms, subject to
bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and
other laws of general applicability relating to or affecting creditors' rights
and to general equity principles. The Joint Litigants' Agreement has been duly
authorized by each of the Purchaser and the Guarantor and, upon the due
execution and delivery thereof by each of the Purchaser and Guarantor, will be
the valid and binding obligation of the Purchaser and the Guarantor, enforceable
against the Purchaser and the Guarantor in accordance with its terms, subject to
bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and
other laws of general applicability relating to or affecting creditors' rights
and to general equity principles.
(c) Conflicts; Consents. Neither the execution and delivery of
this Agreement or the Joint Litigants' Agreement, the consummation of the
transactions contemplated hereby or thereby nor compliance by the Purchaser and
the Guarantor with any of the provisions hereof or thereof will (i) conflict
with or result in a breach of the charter, by-laws or other constitutive
documents of the Purchaser or the Guarantor, (ii) conflict with or result in a
default (or give rise to any right of termination, cancellation or acceleration)
under any of the provisions of any note, bond, lease, mortgage, indenture,
license, franchise, permit, agreement or other instrument or obligation to which
the Purchaser or the Guarantor is a party, or by which the Purchaser or the
Guarantor or the Purchaser's or the Guarantor's properties or assets, may be
bound or affected, except for such conflict, breach or default as to which
requisite waivers or consents shall be obtained before the Closing, or (iii)
violate any law, statute, rule or regulation or order, writ, injunction or
decree applicable to the Purchaser or the Guarantor or the Purchaser's or the
Guarantor's properties or assets. Except for compliance
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with any applicable requirements under the HSR Act, no consent or approval by,
or any notification of or filing with, any governmental authority or body is
required in connection with the execution, delivery and performance by the
Purchaser or the Guarantor of this Agreement or the Joint Litigants' Agreement
or the consummation of the transactions contemplated hereby or thereby.
(d) Regulatory Status. Neither the Purchaser nor the Guarantor is
(i) an "electric utility company", a "holding company", or either a "subsidiary
company" or an "affiliate" of a "holding company" as such terms are defined in
PUHCA, (ii) subject to regulation under PUHCA (other than any such regulation
contemplated by Section 9(a)(2), 32 or 33 of PUHCA), (iii) subject to regulation
as an "electric utility" or a "public utility" as such terms are defined in the
Federal Power Act (other than as contemplated by 18 C.F.R. Section 292.601(c) or
Section 32 or 33 of PUHCA), (iv) a wholly or partially owned subsidiary company,
within the meaning of 18 C.F.R. Section 292.206 and the decisions of FERC
interpreting such provision, of any of the types of entities listed in clauses
(i) through (iii) above, inclusive, (v) subject to regulation by any state
respecting the rates of electric utilities or the financial and organizational
regulation of electric utilities as those terms are used in Section 210(e) of
PURPA, except with respect to participation in, or ownership of, an "exempt
wholesale generator" as such term is defined in Section 32 of PUHCA, or (vi) a
Person primarily engaged in the generation or sale of electric power (other than
electric power solely from qualifying cogeneration facilities, qualifying small
power production facilities, exempt wholesale generators or foreign utilities
companies (as defined in Section 33 of PUHCA)) within the meaning of the Federal
Power Act.
(e) Brokers. No agent, broker, investment banker or other Person
acting on behalf of the Purchaser or the Guarantor or under the authority of the
Purchaser or the Guarantor is or will be entitled to any broker's or finder's
fee or any other commission or similar fee directly or indirectly from any of
the parties hereto in connection with any of the transactions contemplated
hereby.
(f) Investment Representations. (i) The Purchaser is an
"accredited investor" within the meaning of Rule 501 under the Securities Act of
1933 (the "Securities Act");
(ii) the Purchaser has sufficient knowledge and experience
in investing in companies similar to the Companies so as to be able to evaluate
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<PAGE> 28
the risks and merits of its investment in the Companies and it is able
financially to bear the risks thereof;
(iii) the Purchaser has had an opportunity to discuss the
transactions contemplated by this Agreement and the Companies' business,
management and financial affairs with the management of each of the Companies;
(iv) the Shares are being acquired by the Purchaser solely
for its own account for the purpose of investment and not with a view to, or for
sale in connection with, any distribution thereof within the meaning of the
Securities Act; and
(v) the Purchaser understands that (A) the Shares have not
been registered under the Securities Act, (B) the Shares must be held
indefinitely unless a subsequent disposition thereof is registered under the
Securities Act or is exempt from such registration and (C) each of the Companies
will make a notation on its stock transfer books to such effect.
(g) Seller's Representations and Warranties. Neither the
Purchaser nor the Guarantor is aware that any of the Seller's representations
and warranties herein are untrue, provided that nothing discovered (or which
should have been discovered) by the Purchaser or the Guarantor in the course of
its due diligence investigation of the business and affairs of the Companies,
the Subsidiaries and the Partnerships will be considered a waiver of, or a
reduction of the Seller's responsibility for, its representations and warranties
hereunder, except with respect to inaccuracies of which the Purchaser or the
Guarantor is aware and does not make known to the Seller.
ARTICLE III
ADDITIONAL AGREEMENTS
3.1. Expenses, Taxes. Each party hereto shall bear its own costs
and expenses incurred in connection with the transactions contemplated by this
Agreement, including the cost of all income, single business, sales, transfer,
use, gross receipts, registration, stamp and similar taxes arising out of or in
connection with the transactions contemplated by this Agreement. Without
limiting the foregoing, the Seller shall pay any fee due to DLJ.
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<PAGE> 29
3.2. Conduct of Business. (a) Except as set forth in Section
2.2(f) or 3.8 or Schedule 2.2(f) or 3.8 or as otherwise expressly permitted by
this Agreement, or except with the prior written consent of the Purchaser, the
Seller shall cause the Companies and the Subsidiaries to operate their
respective businesses only in the ordinary course of business.
(b) Without limiting the generality of the foregoing, except as
set forth in Section 2.2(f) or 3.8 or Schedule 2.2(f) or 3.8 or as otherwise
expressly permitted by this Agreement, or except with the prior written consent
of the Purchaser, the Seller shall cause the Companies to prohibit, and the
Companies shall cause the Subsidiaries and the Partnerships to prohibit,
directly or indirectly, any state of affairs or action described in clauses (i)
through (xvi) of Section 2.2(f), to the extent any of such matters are within
the control of any of them; provided that, except as set forth in Section
5.2(b), if any of the Partnerships makes any distributions with respect to the
GEI Partnership Interests on or after July 1, 1997, such distributions shall be
retained by the Subsidiary or Subsidiaries receiving such distributions.
3.3. Further Assurances. Each of the parties hereto agrees to use
all commercially reasonable 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
transactions contemplated by this Agreement as expeditiously as practicable and
to ensure that the conditions set forth in Article IV hereof are satisfied,
insofar as such matters are within the control of either of them. In case at any
time after the Closing Date any further action is necessary or desirable to
carry out the purposes of this Agreement, each of the parties to this Agreement
shall take or cause to be taken all such necessary action, including the
execution and delivery of such further instruments and documents, as may be
reasonably requested by either party for such purposes or otherwise to complete
or perfect the transactions contemplated hereby.
3.4. Access and Information. From the date hereof until the first
to occur of the Closing Date and the termination of this Agreement, the Seller
shall cause the Companies and the Subsidiaries to permit the Purchaser and its
agents and representatives to have access to the Companies, the Subsidiaries
and, to the extent within the control of the Companies and the Subsidiaries, the
Partnerships, and their respective officers, counsel, auditors, books and
records, and the opportunity to investigate the Companies', the Subsidiaries'
and the Partnerships' title to property and the condition and nature of their
assets, business and liabilities, in each case upon reasonable notice and
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during normal business hours. All information furnished by the Seller, the
Companies, the Subsidiaries or the Partnerships shall be subject to the terms of
the Confidentiality Agreement, dated June 13, 1997 (the "Confidentiality
Agreement"), between GEI and the Guarantor.
3.5. Public Announcements. The parties shall consult with each
other before issuing, and provide each other the opportunity to review and
comment upon, any press release or other public statements with respect to this
Agreement or the transactions contemplated hereby and, except as may be required
by applicable law or any listing agreement with any national securities
exchange, will not issue any such release or make any such public statement
prior to such consultation.
3.6. Taxes. (a) The Seller shall include the income of the
Companies and the Subsidiaries on the Seller's consolidated Federal income tax
returns, and on each state or local income tax return required to be filed by
the Seller on a consolidated basis (collectively, the "Seller Income Tax
Returns"), for all periods ending on or before the Closing Date. The Seller
shall pay any Federal income taxes, and the state and local income or franchise
taxes related to the Seller Income Tax Returns, attributable to the Companies
and the Subsidiaries for such periods. The Purchaser shall cause the Companies
and the Subsidiaries to furnish tax information to the Seller for inclusion in
the Seller Income Tax Returns for the period which includes the Closing Date in
a manner consistent with the Companies' and the Subsidiaries' past practices.
(b) Each of the Seller and the Purchaser shall make timely and
irrevocable elections under Section 338(h)(10) of the Code and, if permissible,
similar elections under any applicable state or local income tax laws with
respect to the Companies (the "Elections"). Each of the Seller and the Purchaser
shall report the transaction consistent with the Elections and shall take no
position contrary thereto unless and to the extent required to do so pursuant to
a determination (as defined in Section 1313(a) of the Code). Each of the Seller
and the Purchaser shall cause any and all forms necessary to effectuate such
elections (the "Section 338 Forms") to be duly executed by an authorized person
and shall duly and timely file such forms in accordance with applicable tax laws
and the terms of this Agreement.
(c) Each of Seller and Purchaser will reflect the Allocation (as
defined in Section 4.1(j)) in all applicable tax returns filed by any of them,
including the Section 338 Forms. Each of Seller and Purchaser shall not take a
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position inconsistent with such allocation unless and to the extent required to
do so pursuant to a determination (as defined in Section 1313(a) of the Code).
3.7. Employees of the Companies. At the Closing, neither the
Companies nor any of the Subsidiaries shall have any employees.
3.8. Divestiture of Certain Assets and Subsidiaries. The
Companies shall transfer the assets and capital stock of the corporations listed
on Schedule 3.8-1 to the Seller or any affiliate thereof on or before the
Closing Date (the "Divested Assets") and the Seller or any affiliate thereof
shall assume the liabilities of the Companies listed on Schedule 3.8-2 on or
before the Closing Date (the "Assumed Liabilities"). The Purchaser hereby waives
any right or claim to the Divested Assets.
3.9. Put Right. (a) Subject to the conditions set forth in
paragraph (b), at any time in the period between the Closing Date and the third
anniversary of the Closing Date (the "Exercise Period"), the Purchaser shall
have the right (the "Put Right") on one occasion, in its sole discretion, to
require the Seller, or a Person designated by the Seller, to purchase from the
Purchaser all, but not less than all, of all of the Purchaser's right, title and
interest in the shares of capital stock of Tuscarora Energy Corp. ("TEC"),
currently owned by GEI (the "TEC Shares"), at a price of $18,900,000 (the "Put
Price"), as adjusted in accordance with the next succeeding sentence. The Put
Price shall be (i) reduced by the sum of (A) the amount of all cash
distributions of any type received by TEC from Lockport from the Closing Date to
the Put Closing Date (as defined below), plus (B) the fair market value of all
non-cash distributions of any type received by TEC from Lockport from the
Closing Date to the Put Closing Date, plus (C) the amount of all payments from
the Seller to any Indemnified Person (as defined in Section 5.3) pursuant to
Section 5.1 from the Closing Date to the Put Closing Date, to the extent such
payments under this subclause (C) arise from, are by reason of, or are in
connection with, breaches of representations and warranties or covenants of the
Seller herein relating to Lockport or TEC and (ii) increased by the amount of
any capital contribution made to Lockport by TEC from the Closing Date to the
Put Closing Date, provided that the aggregate increases in the Put Price due to
capital contributions shall not be greater than the aggregate distributions
previously received after the Closing Date by TEC from Lockport. Notwithstanding
the foregoing, in no event shall the Put Price be greater than $18,900,000.
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(b) It shall be a condition precedent to the Purchaser's right to
exercise the Put Right that on the date of exercise of the Put Right and on the
Put Closing Date (as defined in paragraph (c)), TEC owns all of the assets it
owns as of the Closing Date.
(c) If the Purchaser wishes to exercise the Put Right, it shall
give the Seller written notice thereof within the Exercise Period (the "Exercise
Notice") together with a certificate of its Chief Financial Officer, in form and
substance reasonably satisfactory to the Seller, (i) certifying the amounts, if
any, either (x) received on or before the date of such notice by TEC or any
Indemnified Person as described in subclauses (i)(A), (B) and (C) in paragraph
(a) or (y) contributed by TEC to Lockport as described in clause (ii) in
paragraph (a), and (ii) stating that the conditions set forth in paragraph (b)
have been satisfied as of the date of such certificate (the "Exercise Notice
Certificate"). The purchase and sale of the TEC Shares shall be consummated
within 20 business days following the receipt by Seller of the Exercise Notice
(the "Put Closing Date").
(d) In order to confirm the information set forth in the Exercise
Notice Certificate, between the date of the receipt of the Exercise Notice by
Seller and the Put Closing Date, the Purchaser shall, and shall cause TEC and,
to the extent within Purchaser's control, Lockport, to permit the Seller and its
agents and representatives to have access to the Purchaser, TEC and Lockport,
and each of their respective officers, auditors, books and records, upon
reasonable notice and during normal business hours. All information so furnished
to the Seller shall be held in strict confidence by the Seller.
(e) On the Put Closing Date, the Purchaser shall (i) provide a
certificate of the Chief Financial Official, in form and substance reasonably
satisfactory to the Seller, stating that the information set forth in the
Exercise Notice Certificate is true and correct as if provided on and as of the
Put Closing Date and (ii) convey to the Seller ownership of all of the TEC
shares, free and clear of all Claims (other than Claims which exist at the time
of the Closing). Contemporaneously with such provision and conveyance, the
Seller shall deliver the adjusted Put Price by wire transfer of immediately
available funds to the Purchaser.
3.10. Corporate Name Change. Within 30 days after the Closing
Date, the Purchaser shall cause the name of GEI to be changed to a name that
does not include "Gas Energy Inc." or any name similar thereto.
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ARTICLE IV
CLOSING CONDITIONS
4.1. Conditions of Obligations of the Purchaser. The obligations
of the Purchaser to perform this Agreement are subject to the satisfaction, at
or prior to the Closing, of the following conditions, unless waived by the
Purchaser:
(a) Representations and Warranties. The representations and
warranties of the Seller contained herein shall be true and correct in all
material respects as of the date hereof and as of the Closing Date as if made on
and as of the Closing Date, and each of the Seller and the Companies shall have
performed and complied with all covenants and agreements required to be
performed or complied with by it on or prior to the Closing Date.
(b) Certificates. The Purchaser shall have received certificates
of the President or any Vice President of each of the Seller and the Companies
confirming the matters set forth in Section 4.1(a), in form and substance
reasonably satisfactory to the Purchaser.
(c) Consents and Waivers. The Purchaser shall have received
copies of all duly executed and delivered waivers and consents contemplated by
Section 2.2(d) and Schedule 2.2(d)-1, all in form and substance reasonably
satisfactory to the Purchaser, provided that, if the Seller shall fail to
receive the waiver of TBG Cogen Partners' termination right pursuant to the BFM
Fuel Management Agreement (as defined in Schedule 2.2(k)-1) or the consent of
Grumman Aerospace Corporation under Section 17.9 of the Grumman Energy Purchase
Agreement (as defined in Schedule 2.2(d)-1) by the time the parties are
otherwise prepared to close, the Seller shall cause this condition (c) with
respect to such termination or consent right to be satisfied by causing all of
the capital stock of Bethpage Fuel Management Inc. to be distributed to the
Seller, in which case (x) the Purchase Price shall be permanently reduced by
$6,000,000 (without duplication of any reduction under Section 4.2(c)) and (y)
Bethpage Fuel Management Inc. shall thereby be deemed to be a Divested Asset for
all purposes of this Agreement, provided that, in no event shall there be any
reduction in the Purchase Price under this Section 4.1(c) in the event of any
reduction in the Purchase Price under Sections 4.1(i) and 4.2(h). The Seller
shall have obtained, or cause to have been obtained, a waiver or cure of the
defaults described under item 1 on Schedule 2.2(k)-2. Any applicable
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waiting period under the HSR Act relating to the transactions contemplated
hereby shall have expired or been duly terminated.
(d) Opinions of Counsel. The Purchaser shall have received the
opinions, dated the Closing Date, of each of Cullen and Dykman and Howard, Darby
& Levin, counsel to the Seller and the Companies, in substantially the forms of
Exhibits B-1 and B-2 (with respect to the opinions of Cullen and Dykman) and
Exhibit B-3 (with respect to the opinion of Howard, Darby & Levin).
(e) Joint Litigants' Agreement. The Seller shall have entered
into the Joint Litigants' Agreement.
(f) Share Certificates and Corporate Records. The Purchaser shall
have received certificates representing the Shares, together with stock powers
duly endorsed for transfer to the Purchaser, and the complete share ledgers,
minute books and similar corporate records of each of the Companies and the
Subsidiaries.
(g) Legal Bar. No injunction or orders issued by a court of
competent jurisdiction that prohibits the consummation of the transactions
contemplated herein shall be in effect.
(h) Resignations. Each of the current directors and officers of
the Companies and the Subsidiaries shall have resigned effective no later than
the Closing Date.
(i) Amendment of TBG Balancing Agreement. The transportation
arrangements associated with TBG Cogen Partners shall have been amended to
conform with the assumptions in the pro forma projections previously provided to
the Purchaser by the Companies, provided that in the event such arrangements
have not been so conformed by the time the parties are otherwise prepared to
close, the Seller shall cause this condition (i) to be satisfied by giving
written notice of such failure to the Purchaser, in which case the Purchase
Price shall be permanently reduced by $2,150,000 (without duplication of any
reduction under Section 4.2(h)). The condition set forth in the preceding
sentence shall be deemed to have been satisfied, and there shall be no reduction
in the Purchase Price under this Section 4.1(i), in the event of any reduction
in the Purchase Price under Sections 4.1(c) and 4.2(c).
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(j) Allocation. Each of Seller and Purchaser shall have agreed to
an allocation of the Aggregate Deemed Sale Price (as defined under applicable
Treasury Regulations promulgated pursuant to the Code) of the assets of the
Company (the "Allocation").
(k) Agreements. Purchaser shall have received a certified copy of
each of the agreements set forth in Schedule 2.2(k)-1, certified as true and
correct by an officer of GEI.
4.2. Conditions of Obligations of the Seller. The obligations of
the Seller to perform this Agreement are subject to the satisfaction, at or
prior to the Closing, of the following conditions, unless waived by the Seller:
(a) Representations and Warranties. The representations and
warranties of the Purchaser and the Guarantor contained herein shall be true and
correct in all material respects as of the date hereof and as of the Closing
Date as if made on and as of the Closing Date, and each of the Purchaser and the
Guarantor shall have performed and complied with all covenants and agreements
required to be performed or complied with by it on or prior to the Closing Date.
(b) Certificate. The Seller shall have received a certificate of
the President or any Vice President of each of the Purchaser and the Guarantor
confirming the matters set forth in Section 4.2(a), in form and substance
reasonably satisfactory to the Seller.
(c) Consents and Waivers. The Seller shall have received copies
of all duly executed and delivered waivers and consents contemplated by Section
2.2(d) and Schedule 2.2(d)-1, all in form and substance reasonably satisfactory
to the Seller, provided that, if the Seller shall fail to receive the waiver of
TBG Cogen Partners' termination right pursuant to the BFM Fuel Management
Agreement or the consent of Grumman Aerospace Corporation under Section 17.9 of
the Grumman Energy Purchase Agreement by the time the parties are otherwise
prepared to close, the Seller shall cause this condition (c) with respect to
such termination or consent right to be satisfied by causing all of the capital
stock of Bethpage Fuel Management Inc. to be distributed to the Seller, in which
case (x) the Purchase Price shall be permanently reduced by $6,000,000 (without
duplication of any
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reduction under Section 4.1(c)) and (y) Bethpage Fuel Management Inc. shall
thereby be deemed to be a Divested Asset for all purposes of this Agreement,
provided that, in no event shall there be any reduction in the Purchase Price
under this Section 4.2(c) in the event of any reduction in the Purchase Price
under Sections 4.1(i) and 4.2(h). Any applicable waiting period under the HSR
Act relating to the transactions contemplated hereby shall have expired or been
duly terminated.
(d) Opinion of Counsel. The Seller shall have received opinions,
dated the Closing Date, of each of Joseph E. Ronan, Jr., Esq., General Counsel
of the Guarantor, and Washburn, Briscoe & McCarthy, counsel to the Purchaser and
the Guarantor, in substantially the forms of Exhibits C-1 and C-2, respectively.
(e) Joint Litigants' Agreement. The Purchaser, the Guarantor, the
Companies, Airport Cogen Corp. and Aviation Funding Corp. shall each have
entered into the Joint Litigants' Agreement.
(f) Purchase Price. The Seller shall have received the Purchase
Price, as adjusted, in accordance with Section 1.2.
(g) Legal Bar. No injunction or orders issued by a Court of
competent jurisdiction that prohibits the consummation of the transactions
contemplated herein shall be in effect.
(h) Amendment of TBG Balancing Agreement. The transportation
arrangements associated with TBG Cogen Partners shall have been amended to
conform with the assumptions in the pro forma projections previously provided to
the Purchaser by the Companies, provided that in the event such arrangements
have not been so conformed by the time the parties are otherwise prepared to
close, the Seller shall cause this condition (h) to be satisfied by giving
written notice of such failure to the Purchaser, in which case the Purchase
Price shall be permanently reduced by $2,150,000 (without duplication of any
reduction under Section 4.1(i)). The condition set forth in the preceding
sentence shall be deemed to have been satisfied, and there shall be no reduction
in the Purchase Price under this Section 4.2 (h), in the event of any reduction
in the Purchase Price under Sections 4.1(c) and 4.2(c).
(i) Allocation. Each of the Seller and the Purchaser shall have
agreed to the Allocation.
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ARTICLE V
INDEMNITY
5.1. General. (a) The Seller indemnifies and holds harmless the
Purchaser and its affiliates and its former, present and future directors,
officers, employees and other agents and representatives from and against any
and all liabilities, judgments, claims, settlements, losses, damages, fees,
liens, taxes, penalties, obligations and expenses incurred or suffered by any
such Person directly or indirectly arising from, by reason of, or in connection
with, (i) any misrepresentation or breach of any representation or warranty of
the Seller contained in Section 2.1 and 2.2, (ii) any breach by Seller of any of
its covenants or agreements in this Agreement, (iii) the Divested Assets and
Assumed Liabilities and (iv) the litigation and disputes listed on Schedule
2.2(l)-1, other than the NYSEG Litigation and the Lilco Litigation (as such
terms are defined in Schedule 2.2(l)-1).
(b) Each of the Purchaser and the Guarantor, jointly and
severally, indemnifies and holds harmless the Seller and its affiliates and its
former, present and future directors, officers, employees and other agents and
representatives from and against any and all liabilities, judgments, claims,
settlements, losses, damages, fees, liens, taxes, penalties, obligations and
expenses incurred or suffered by any such Person directly or indirectly arising
from, by reason of, or in connection with (i) any misrepresentation or breach of
any representation or warranty of the Purchaser or the Guarantor contained in
Section 2.3 or (ii) any breach by Purchaser or the Guarantor of any of its
covenants or agreements in this Agreement.
(c) An Indemnifying Party (as defined in Section 5.3) under this
Section 5.1 shall be entitled to participate in and, if (i) in the judgment of
the Indemnified Party (as defined in Section 5.3) such claim can properly be
resolved by money damages alone and the Indemnifying Party has the financial
resources to pay such damages and (ii) the Indemnifying Party admits that this
indemnity fully covers the claim or litigation, the Indemnifying Party shall be
entitled to direct the defense of any claim at its expense, but such defense
shall be conducted by legal counsel reasonably satisfactory to the Indemnified
Party. An Indemnified Party shall not make any settlement of any claim or
litigation under this Section 5.1 without the written consent of the
Indemnifying Party.
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(d) No Indemnified Party will seek indemnification under this
Section 5.1, except in connection with any breach by the Seller of its covenant
in the proviso to Section 3.2(b), until the date on which all unreimbursed
claims by such party under this Section 5.1 exceed $750,000 in the aggregate, in
which case the Indemnified Party shall be entitled to indemnity for the full
amount of all of its claims.
5.2. KIAC Construction Disputes. (a) From and after the Closing
Date, the Seller shall indemnify and hold harmless the Purchaser and the
Guarantor (without duplication) from and against (i) any and all liabilities,
judgments, claims, settlements, losses, damages, fees, liens, penalties,
obligations and expenses incurred or suffered by the Purchaser, GEI, Airport
Cogen Corp. ("ACC") or Aviation Funding Corp. ("AFC") and (ii) 50% of any and
all liabilities, judgments, settlements, losses, damages, fees, liens,
penalties, obligations and expenses incurred or suffered by KIAC Partners
("KIAC") or EnergyPro Construction Partners ("EnergyPro"), in each case arising
out of any claim or dispute (each such claim or dispute, a "KIAC Construction
Claim" and, collectively, the "KIAC Construction Claims") relating to any of the
agreements listed on Schedule 5.2(a) as in effect on the date hereof (each such
agreement, a "KIAC Construction Agreement" and, collectively, the "KIAC
Construction Agreements").
(b) Notwithstanding the proviso in Section 1.2(b)(i) and the
proviso in Section 3.2(b), from and after the date hereof, the Seller shall be
entitled to the benefit of and, prior to the Closing Date, may cause the
distribution of (without duplication), (i) all judgments, settlements, damages,
fees, penalties, expenses or awards realized by the Purchaser, GEI, ACC or AFC
and (ii) 50% of any judgments, settlements, damages, fees, penalties, expenses
or awards realized by KIAC or EnergyPro, in each case on account of any claims
made by any such Person relating to the KIAC Construction Agreements, and from
and after the Closing Date, the Purchaser shall pay or cause to be paid to
Seller all of the amounts set forth in the foregoing clauses (i) and (ii).
(c) As between the Seller and the Purchaser, the Seller shall
assume and direct the defense of all KIAC Construction Claims and the
prosecution of any claims referred to in paragraph (b) above, in each case with
Kalkines, Arky, Zall & Bernstein LLP, counsel to KIAC and EnergyPro, or any
successor law firm selected or approved by the Seller in its sole discretion.
Except for the fees and disbursements of counsel selected under the immediately
preceding sentence, the Seller shall not be liable to the Purchaser under this
Section 5.2 for any legal expenses incurred by the Purchaser, GEI, ACC, AFC,
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KIAC or EnergyPro in connection with the KIAC Construction Claims or any claims
referred to in paragraph (b) above.
(d) As a condition to the Purchaser's entitlement to
indemnification pursuant to this Section 5.2, the Purchaser shall cooperate with
the Seller, shall cause each of GEI, ACC and AFC to cooperate with the Seller,
and shall use all commercially reasonable efforts to cause each of KIAC and
EnergyPro to cooperate with the Seller, in each case in all matters relating to
the KIAC Construction Claims and any claims under paragraph (b) above. Such
cooperation shall include the retention and, upon the Seller's reasonable
request, the provision to the Seller of, records and information which are
relevant to any such claims, and making employees available, upon the Seller's
reasonable request, to provide additional information and explanation of any
records and information provided hereunder. The Purchaser shall not admit to any
liability with respect to, or settle, compromise or discharge, any such claims,
without the Seller's prior written consent. The Purchaser shall prevent each of
GEI, ACC and AFC from admitting to any liability with respect to, or settling,
compromising or discharging, any such claim, and shall use all commercially
reasonable efforts to prevent each of KIAC and EnergyPro from doing the same, in
each case without the Seller's prior written consent. The Purchaser shall, with
respect to any such claims, agree to any settlement, compromise or discharge,
shall cause each of GEI, ACC and AFC to agree to any settlement, compromise or
discharge, and shall use all commercially reasonable efforts to cause KIAC and
EnergyPro to agree to any settlement, compromise or discharge, in each case
which the Seller may recommend and which by its terms obligates the Seller to
pay the full amount of the liability in connection therewith.
5.3. Notices. In case any claim or litigation which might give
rise to any obligation of a party under this Article V (each an "Indemnifying
Party") shall come to the attention of the party seeking indemnification
hereunder (the "Indemnified Party"), the Indemnified Party shall promptly notify
the Indemnifying Party in writing of the existence and amount thereof. The
Indemnifying Party shall promptly notify the Indemnified Party in writing if it
accepts such claim or litigation as being within its indemnification obligations
under this Article V. Such response shall be delivered no later than 30 days
after the initial notification from the Indemnified Party; provided that, if the
Indemnifying Party reasonably cannot respond to such notice within 30 days, the
Indemnifying Party shall respond to the Indemnified Party as soon thereafter as
reasonably possible.
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5.4. Insurance and Tax Benefits. The amount of any claim by an
Indemnified Party for indemnification pursuant to this Article V shall be
computed net of insurance proceeds and tax benefits received by such Indemnified
Party on account of such claim.
ARTICLE VI
MISCELLANEOUS
6.1. Entire Agreement. This Agreement and the Schedules and
Exhibits contain the entire agreement among the parties with respect to the
transactions contemplated by this Agreement and, except for the Confidentiality
Agreement (which shall remain in full force and effect in accordance with its
terms), supersede all prior agreements or understandings among the parties.
6.2. Aggregate Liability. The aggregate liability of the Seller
under Article V or for any claim for any breach or violation of any provision of
this Agreement shall not exceed (i) the Purchase Price (as adjusted pursuant to
Sections 1.2, 4.1 and 4.2) minus (ii) the Put Price, if any, paid by the Seller
or the Seller's designee upon the exercise of the Put Right.
6.3. Termination. (a) This Agreement may be terminated and the
transactions contemplated hereby may be abandoned at any time prior to the
Closing:
(i) by the mutual written consent of the Seller, the
Companies, the Purchaser and the Guarantor;
(ii) by the Purchaser at any time after December 31, 1997
if any of the conditions provided for in Section 4.1 shall not have been waived
in writing by the Purchaser or fully satisfied prior to such date;
(iii) by the Seller at any time after December 31, 1997 if
any of the conditions provided for in Section 4.2 shall not have been waived in
writing by the Seller or fully satisfied prior to such date;
(iv) by the Seller in the event of a material violation or
breach by the Purchaser or the Guarantor of its agreements, representations or
warranties contained in this Agreement that has rendered the satisfaction of any
condition to the obligations of the Seller impossible and the Seller is not
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in material violation or breach of its agreements, representations or warranties
contained in this Agreement; or
(v) by the Purchaser or the Guarantor in the event of a
material violation or breach by the Seller or either of the Companies of their
agreements, representations or warranties contained in this Agreement that has
rendered the satisfaction of any condition to the obligations of the Purchaser
impossible and the Purchaser is not in material violation or breach of its
agreements, representations or warranties contained in this Agreement.
(b) In the event of termination and abandonment by the Seller or
the Purchaser, or both, pursuant to this Section 6.3, written notice thereof
shall forthwith be given to the other party and this Agreement shall terminate
and be abandoned without further action by Purchaser or the Seller, except that
the obligations of the parties under Section 3.1 and the last sentence of
Section 3.4 shall survive. If this Agreement is terminated as provided herein:
(i) each party will redeliver all documents, work papers
and other material of any other party relating to the transactions contemplated
hereby, whether obtained before or after the execution hereof, to the party
furnishing the same; and
(ii) no party hereto shall have any liability or further
obligation to the other parties to this Agreement, except as provided in Section
3.1 and the last sentence of Section 3.4, and except for such legal and
equitable rights and remedies that any party may have by reason of any breach or
violation of this Agreement by any party.
6.4. Descriptive Headings; Certain Interpretations. (a)
Descriptive headings are for convenience only and shall not control or affect
the meaning or construction of any provision of this Agreement.
(b) Except as otherwise expressly provided in this Agreement, the
following rules of interpretation apply to this Agreement: (i) the singular
includes the plural and the plural includes the singular; (ii) "or" and "either"
are not exclusive and "include" and "including" are not limiting; (iii) a
reference to any agreement or other contract includes schedules and exhibits
thereto and permitted supplements and amendments thereof; (iv) a reference to a
law includes any amendment or modification to such law and any rules or
regulations issued thereunder; (v) a reference to a Person includes its
permitted successors and assigns; (vi) a reference to generally accepted
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accounting principles refers to generally accepted accounting principles of the
United States; (vii) the phrase "to the knowledge of," when used in respect of
the Seller, shall be deemed to mean the actual knowledge of any of the Chief
Executive Officer or Chief Financial Officer of the Seller or the Chief
Executive Officer, the Vice President and Treasurer or the Vice
President-Project Development of GEI, after reasonable inquiry into the matters
pertaining to such phrase; and (viii) a reference in this Agreement to an
Article, Section, Exhibit or Schedule is to the Article, Section, Exhibit or
Schedule of this Agreement.
(c) Matters disclosed by the Seller and the Companies to the
Purchaser or the Guarantor pursuant to any Section or Schedule of this Agreement
shall be deemed to be disclosed with respect to all Sections and Schedules of
this Agreement.
6.5. Notices. All notices, requests and other communications to
any party hereunder shall be in writing and sufficient if delivered personally
or sent by telecopy (with confirmation of receipt) or by registered or certified
mail, postage prepaid, return receipt requested, addressed as follows:
If to the Purchaser, to:
Calpine Eastern Corporation
50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115
Telecopy: (408) 995-0505
Attention: Ron A. Walter and
Joseph E. Ronan, Jr., Esq.
with a copy to:
Washburn, Briscoe & McCarthy
55 Francisco Street, Suite 600
San Francisco, California 94133
Telephone: (415) 421-3200
Telecopy: (415) 421-5044
Attention: David C. Spielberg, Esq.
If to the Guarantor, to:
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Calpine Corporation
50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115
Telecopy: (408) 995-0505
Attention: Ron A. Walter and
Joseph E. Ronan, Jr., Esq.
with a copy to:
Washburn, Briscoe & McCarthy
55 Francisco Street, Suite 600
San Francisco, California 94133
Telephone: (415) 421-3200
Telecopy: (415) 421-5044
Attention: David C. Spielberg, Esq.
If to the Seller, to:
The Brooklyn Union Gas Company
One MetroTech Center
Brooklyn, New York 11201
Telephone: (718) 403-2858
Telecopy: (718) 858-6431
Attention: Mr. Theodore Spar
with a copy to:
Howard, Darby & Levin
1330 Avenue of the Americas
New York, New York 10019
Telephone: (212) 841-1075
Telecopy: (212) 841-1010
Attention: William R. Collins, Esq.
-37-
<PAGE> 44
and
Cullen and Dykman
177 Montague Street
Brooklyn, New York 11201
Telephone: (718) 780-0053
Telecopy: (718) 855-4282
Attention: Steven L. Zelkowitz, Esq.
If to the Companies, to:
Gas Energy Inc.
Gas Energy Cogeneration Inc.
111 Livingston Street
Brooklyn, New York 11201
Telephone: (718) 403-2624
Telecopy: (718) 797-4705
Attention: Mr. David S. Milne, Jr.
with a copy to:
Howard, Darby & Levin
1330 Avenue of the Americas
New York, New York 10019
Telephone: (212) 841-1075
Telecopy: (212) 841-1010
Attention: William R. Collins, Esq.
and
Cullen and Dykman
177 Montague Street
Brooklyn, New York 11201
Telephone: (718) 780-0053
Telecopy: (718) 855-4282
Attention: Steven L. Zelkowitz, Esq.
or to such other address or telecopy number as the party to whom notice is to be
given may have furnished to the other parties in writing in accordance herewith.
Each such notice, request or communication shall be effective when received or,
if given by mail, when delivered at the address specified in this
-38-
<PAGE> 45
Section 6.5 or on the fifth business day following the date on which such
communication is posted, whichever occurs first.
6.6. Counterparts. This Agreement may be executed in any number
of counterparts, and each such counterpart hereof shall be deemed to be an
original instrument, but all such counterparts together shall constitute but one
agreement.
6.7. Survival. All representations and warranties of the Seller
in Sections 2.1 and 2.2 (except Section 2.1(a), Section 2.1(c) (as to the
Seller's power and authority to transfer title to the Shares), the last sentence
of Section 2.2(a)(ii), and Section 2.2(g)), and of the Purchaser and the
Guarantor contained in Section 2.3, shall each survive the Closing and terminate
and expire on the date that is 18 months after the Closing Date. The
representations and warranties of the Seller in Section 2.1(a), Section 2.1(c)
(as to the Seller's power and authority to transfer title to the Shares) and the
last sentence of Section 2.2(a)(ii) shall survive the Closing indefinitely. The
representations and warranties of the Seller in Section 2.2(g) shall survive the
Closing and terminate and expire at the end of the applicable statute of
limitations. The indemnification and reimbursement obligations under Section 5.1
(and related obligations under Sections 5.3 and 5.4) shall survive the Closing
and expire on the date that is 18 months after the Closing Date, except with
respect to (x) indemnification claims relating to Section 2.1(a), Section 2.1(c)
(as to the Seller's power and authority to transfer title to the Shares) and the
last sentence of Section 2.2(a)(ii), which shall survive the Closing
indefinitely, and Section 2.2(g), which shall survive the Closing and expire at
the end of the applicable statute of limitations, and (y) any claims for, or any
claims that may result in, any liability, judgment, claim, settlement, loss,
damage, fee, lien, tax, penalty, obligation or expense for which indemnity may
be sought hereunder of which the Indemnifying Party has received written notice
from the Indemnified Party on or before such expiration date. All agreements and
covenants of the parties in Sections 3.1, 3.3, 3.5, 3.6, 3.7, 3.8, 3.9, 3.10,
5.2 (and related obligations under Sections 5.3 and 5.4), 6.1, 6.2, 6.4, 6.5,
this 6.7, 6.8, 6.9, 6.10, 6.11, 6.12 and 6.13 shall survive the Closing until
such agreements and covenants are paid, performed or discharged in full. All
other representations and warranties, agreements and covenants of the parties
contained herein shall terminate and expire upon the Closing and be of no
further force or effect thereafter, and after the Closing, no party shall have
any liability to any other party with respect thereto.
-39-
<PAGE> 46
6.8. Benefits of Agreement. All of the terms and provisions of
this Agreement shall be binding upon and inure to the benefit of the parties
hereto and their respective successors and assigns. This Agreement is for the
sole benefit of the parties hereto and not for the benefit of any third party.
6.9. Amendments and Waivers. No modification, amendment or
waiver, of any provision of, or consent required by, this Agreement, nor any
consent to any departure herefrom, shall be effective unless it is in writing
and signed by the parties hereto. Such modification, amendment, waiver or
consent shall be effective only in the specific instance and for the purpose for
which given.
6.10. Assignment. This Agreement and the rights and obligations
hereunder shall not be assignable or transferable by either party hereto without
the prior written consent of the other parties hereto, provided that the Seller
may assign all or part of its rights and obligations hereunder to any Person
owning all of the outstanding capital stock of the Seller.
6.11. Guarantee. The Guarantor hereby unconditionally and
irrevocably guarantees the full payment and performance of all obligations of
the Purchaser under this Agreement.
6.12. GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND
CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD
TO CONFLICT OF LAWS PRINCIPLES.
6.13. CONSENT TO JURISDICTION. EACH OF THE PURCHASER AND THE
GUARANTOR HEREBY SUBMITS TO THE NONEXCLUSIVE JURISDICTION OF THE UNITED STATES
DISTRICT COURT FOR THE EASTERN DISTRICT OF NEW YORK AND OF ANY NEW YORK STATE
COURT SITTING IN NEW YORK CITY FOR PURPOSES OF ALL LEGAL PROCEEDINGS ARISING OUT
OF OR RELATING TO THIS AGREEMENT OR THE JOINT LITIGANTS' AGREEMENT OR THE
TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY. EACH OF THE PURCHASER AND THE
GUARANTOR IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY
OBJECTION WHICH IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY
SUCH PROCEEDING BROUGHT IN SUCH A COURT AND ANY CLAIM THAT ANY SUCH PROCEEDING
BROUGHT IN SUCH A COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. EACH OF THE
PURCHASER AND THE GUARANTOR HEREBY APPOINTS CT CORPORATION SYSTEM (THE "AGENT"),
AT THE AGENT'S OFFICES AT 1633 BROADWAY, 23RD FLOOR, NEW YORK, NEW YORK 10019,
OR ITS OFFICE AT SUCH OTHER ADDRESS IN NEW YORK, NEW YORK, AS IS HEREAFTER
FURNISHED TO THE SELLER, AS ITS AGENT TO ACCEPT AND ACKNOWLEDGE ON
-40-
<PAGE> 47
ITS BEHALF SERVICE OF ANY AND ALL PROCESS THAT MAY BE SERVED IN ANY SUCH LEGAL
PROCEEDING. ANY AND ALL SERVICE OF PROCESS AND ANY OTHER NOTICE IN ANY SUCH
PROCEEDING SHALL BE EFFECTIVE AGAINST THE PURCHASER AND THE GUARANTOR IF GIVEN
PERSONALLY OR BY REGISTERED OR CERTIFIED MAIL, RETURN RECEIPT REQUESTED, OR BY
ANY OTHER MEANS OF MAIL THAT REQUIRES A SIGNED RECEIPT, POSTAGE PREPAID, MAILED
TO THE PURCHASER AND THE GUARANTOR OR BY PERSONAL SERVICE ON THE AGENT, WITH A
COPY OF SUCH PROCESS MAILED TO THE PURCHASER AND THE GUARANTOR BY FIRST CLASS
MAIL OR REGISTERED OR CERTIFIED MAIL, RETURN RECEIPT REQUESTED, POSTAGE PREPAID.
NOTHING HEREIN SHALL BE DEEMED TO AFFECT THE RIGHT OF THE SELLER TO SERVE
PROCESS IN ANY MANNER PERMITTED BY LAW OR TO COMMENCE LEGAL PROCEEDINGS OR
OTHERWISE PROCEED AGAINST THE PURCHASER AND THE GUARANTOR IN ANY JURISDICTION
OTHER THAN THE STATE OF NEW YORK.
-41-
<PAGE> 48
IN WITNESS WHEREOF, each of the parties has caused this Agreement
to be duly executed and delivered as of the day and year first above written.
GAS ENERGY INC.
By:__________________________________
Name:
Title:
GAS ENERGY COGENERATION INC.
By:__________________________________
Name:
Title:
THE BROOKLYN UNION GAS COMPANY
By:__________________________________
Name:
Title:
CALPINE EASTERN CORPORATION
By:___________________________________
Name:
Title:
CALPINE CORPORATION
By:___________________________________
Name:
Title:
-42-
<PAGE> 1
Exhibit: 10.11.4
FIRST AMENDMENT
TO THE STOCK PURCHASE AGREEMENT
AMONG
GAS ENERGY, INC., GAS ENERGY COGENERATION INC.,
THE BROOKLYN UNION GAS COMPANY
AND
CALPINE EASTERN CORPORATION AND CALPINE CORPORATION
Dated August 22 1997;
As Amended
on December 19, 1997
<PAGE> 2
FIRST AMENDMENT, dated December 19, 1997, among Gas Energy Inc., a New York
corporation ("GEI"), Gas Energy Cogeneration Inc., a Delaware corporation
("GECI," and together with GEI, the "Companies"), The Brooklyn Union Gas
Company, a New York corporation (the "Seller"), Calpine Eastern Corporation, a
Delaware corporation (the "Purchaser"), and Calpine Corporation, a Delaware
corporation (the "Guarantor"), to the Stock Purchase Agreement, dated August 22,
1997 (the "Original Agreement"), among the Companies, the Seller, the Purchaser
and the Guarantor.
The Companies, the Seller, the Purchaser and the Guarantor entered into
the Original Agreement relating to the sale to the Purchaser of all of the
outstanding stock of each of the Companies.
The parties desire to amend the Original Agreement in certain respects as
hereinafter set forth.
Capitalized terms used herein and not otherwise defined herein shall have
the respective meanings set forth in the Original Agreement. References to "the
Agreement" or "this Agreement" contained in the Original Agreement and this
Amendment shall mean the Original Agreement as amended by this Amendment.
In consideration of the mutual benefits to be derived from this Amendment
and of the agreements and promises contained herein and other good and valuable
consideration, the parties agree as follows:
1. Section 1.2(a) of the Original Agreement shall be deleted in its
entirety and replaced with the following:
"(a) The purchase price (the "Purchase Price") for the Shares shall
be cash in the amount of $100,899,927 (of which $100,699,927 shall be
consideration for the Shares and $200,000 shall be consideration for the
put options set forth in Sections 3.9 and 3.10), subject to adjustment in
accordance with paragraph (b) below, payable by wire transfer in
immediately available funds, to one or more bank accounts of the Seller.
Such bank accounts shall be designated by the Seller in writing not later
than one business day prior to the Closing Date."
<PAGE> 3
2. The first sentence of Section 1.2(b)(i) of the Original Agreement
shall be deleted in its entirety and replaced with the following:
"(b) (i) No later than January 12, 1998, the Seller shall deliver
to the Purchaser a statement (the "Net Working Capital Statement") setting
forth the Net Working Capital of the Companies as of the Closing Date (the
"Final Net Working Capital"), prepared by a Vice President of the Seller."
3. Schedules 2.2(f) and 2.2(k)-2 are hereby amended by adding thereto
the items set forth on Annexes A-1 and A-2, respectively.
4. Section 3.6(c) of the Original Agreement shall be deleted in its
entirety and replaced with the following:
"(c) Each of the Seller and the Purchaser hereby agree to reflect
the allocation of the Aggregate Deemed Sale Price (as defined under
applicable Treasury Regulations promulgated pursuant to the Code) of the
assets of the Company as set forth in Schedule 3.6(c) hereto in all
applicable tax returns filed by either of them, including the Section 338
Forms. Neither the Seller nor the Purchaser shall take a position
inconsistent with such allocation unless and to the extent required to do
so pursuant to a determination (as defined in Section 1313(a) of the
Code)."
5. Schedule 3.6(c), which is attached as Annex B to this Amendment,
shall be added as a Schedule to the Agreement.
6. Section 3.9(b) of the Original Agreement shall be deleted in its
entirety and replaced with the following:
"(b) It shall be a condition precedent to the Purchaser's right to
exercise the Put Right that, on the date of exercise of the Put Right and
on the Put Closing Date (as defined in paragraph (c)), (i) TEC then owns
all of the assets it owns at the time of the Closing free and clear of all
Claims (other than Claims which exist at the time of the Closing) and (ii)
since the time of the Closing, TEC shall not have issued or made any
commitment to issue any additional shares of capital stock."
<PAGE> 4
7. Section 3.9(e) of the Original Agreement shall be deleted in its
entirety and replaced with the following:
"(e) On the BFM Put Closing Date, the Purchaser shall provide a
certificate of its Chief Financial Officer, in form and substance
reasonably satisfactory to the Seller, stating that the information set
forth in the Exercise Notice Certificate is true and correct as if
provided on and as of the Put Closing Date. Contemporaneously with such
provision and conveyance, the Seller shall deliver the adjusted BFM Put
Price by wire transfer of immediately available funds to the Purchaser."
8. Section 3.10 of the Original Agreement shall be deleted in its
entirety and replaced with the following:
"3.10. BFM Put Right. (a) Subject to the conditions set forth in
paragraph (b), at any time in the period (the "BFM Put Exercise Period")
between the Closing Date and the earlier of (i) the date which is 90 days
after the Closing Date and (ii) the latest of (A) the date on which the
transactions contemplated by the Makowski Stock Purchase Agreement (as
defined below) are consummated, (B) the date on which the transactions
contemplated by the GE Purchase Agreement (as defined below) are
consummated, (C) the date on which the Purchaser receives from Northrup
Grumman Corporation (formerly known as Grumman Aerospace Corporation)
("Grumman") the Grumman Consent (as defined below) and (D) the date on
which the Grumman Amendments (as defined below) are executed, the
Purchaser shall have the right (the "BFM Put Right") on one occasion, in
its sole discretion, to require the Seller, or an affiliate of the Seller
designated by the Seller, to purchase from the Purchaser all, but not less
than all, of the Purchaser's right, title and interest in the shares of
capital stock of Bethpage Fuel Management Inc. ("BFM"), currently owned by
GEI (the "BFM Shares"), at a price of $5,813,230 (the "BFM Put Price"), as
adjusted in accordance with the next succeeding sentence. The BFM Put
Price shall be reduced by the amount of all payments from the Seller to
any Indemnified Person (as defined in Section 5.3) pursuant to Section 5.1
from the Closing Date to the BFM Put Closing Date, to the extent such
payments arise from, are by
<PAGE> 5
reason of, or are in connection with, breaches of representations and
warranties or covenants of the Seller herein relating to BFM. During the
BFM Put Exercise Period, the Purchaser and the Guarantor shall use all
commercially reasonable efforts to obtain from Grumman the Grumman Consent
and the Grumman Amendments. Upon request by the Seller during the BFM Put
Exercise Period, the Purchaser shall provide the Seller with a progress
report or reports on its efforts to obtain the Grumman Consent and the
Grumman Amendments. As used in this Agreement, (i) "Makowski Stock
Purchase Agreement" shall mean the Stock Purchase Agreement by and between
J. Makowski Company, Inc. and Purchaser, dated as of December 19, 1997,
(ii) "GE Purchase Agreement" shall mean the Purchase Agreement by and
between Purchaser, GE Power Funding Corporation and General Electric
Company, dated as of December 19, 1997, (iii) "Grumman Consent" shall mean
the consent of Grumman required pursuant to Section 17.9 of the Grumman
Energy Purchase Agreement (as defined in Schedule 2.2(d)-1) for TBG Cogen
Partners to contract for fuel supply and management with an entity other
than the Seller or an affiliate thereof and (iv) "Grumman Amendments"
shall mean amendments entered into after the Closing Date amending the
Grumman Energy Purchase Agreement and the other agreements between TBG
Cogen Partners and Grumman on terms and conditions satisfactory to the
Purchaser in its sole discretion.
(b) It shall be a condition precedent to the Purchaser's right to
exercise the BFM Put Right that, on the date of exercise of the BFM Put
Right and on the BFM Put Closing Date, (i) all agreements to which BFM is
a party which are listed on Schedule 2.2.(k)-1 (other than the BFM Credit
Agreement (as defined in Schedule 2.2(c)-3)) (collectively, the "BFM
Contracts") remain in full force and effect, without any amendment or
supplement thereto, or waiver of rights thereunder, in each case from and
after the Closing, and none of the BFM Contracts shall be subject to any
Claims (other than Claims which exist at the time of the Closing), (ii)
BFM is not then in default under any BFM Contract as a result of any act
or omission of BFM or the Purchaser from and after the Closing Date and
(iii) since the time of the Closing, BFM shall not have issued or made any
commitment to issue any additional shares of capital stock.
<PAGE> 6
(c) If the Purchaser wishes to exercise the BFM Put Right, it
shall give the Seller written notice thereof within the BFM Put Exercise
Period (the "BFM Put Exercise Notice") together with a certificate of its
Chief Financial Officer, in form and substance reasonably satisfactory to
the Seller, (i) certifying the amounts, if any, which reduce the BFM Put
Price under the second sentence of paragraph (a) and (ii) stating that the
conditions set forth in paragraph (b) have been satisfied as of the date
of such certificate (the "BFM Put Exercise Notice Certificate"). The
purchase and sale of the BFM Shares shall be consummated within five
business days following the receipt by Seller of the BFM Put Exercise
Notice (the "BFM Put Closing Date").
(d) In order to confirm the information set forth in the BFM Put
Exercise Notice Certificate, between the date of the receipt of the BFM
Put Exercise Notice by Seller and the BFM Put Closing Date, the Purchaser
shall permit, and shall cause BFM to permit, the Seller and its agents and
representatives to have access to the Purchaser and BFM, and each of their
respective officers, auditors, books and records, upon reasonable notice
and during normal business hours. All information so furnished to the
Seller shall be held in strict confidence by the Seller.
(e) On the BFM Put Closing Date, the Purchaser shall provide a
certificate of its Chief Financial Officer, in form and substance
reasonably satisfactory to the Seller, stating that the information set
forth in the BFM Put Exercise Notice Certificate is true and correct as if
provided on and as of the BFM Put Closing Date. Contemporaneously with
such provision and conveyance, the Seller shall deliver the adjusted BFM
Put Price by wire transfer of immediately available funds to the
Purchaser."
9. The following Section 3.11 shall be added after Section 3.10 of the
Agreement:
"3.11 Amendment of TBG Balancing Agreement. The Purchaser hereby
acknowledges, and confirms its agreement with, the amended gas
transportation arrangements for TBG Cogen Partners as set forth in Exhibit
D hereto."
<PAGE> 7
10. Exhibit D, which is attached as Annex C to this Amendment, shall be
added as an Exhibit to the Agreement.
11. Section 4.1(c) of the Original Agreement shall be deleted in its
entirety and replaced with the following:
"(c) Consents and Waivers. The Purchaser shall have received
copies of all duly executed and delivered waivers and consents
contemplated by Section 2.2(d) and Schedule 2.2(d)-1 (except the
Grumman Consent), all in form and substance reasonably satisfactory
to the Purchaser. Any applicable waiting period under the HSR Act
relating to the transactions contemplated hereby shall have expired
or been duly terminated."
12. Section 4.1(i) and (j) of the Original Agreement shall be deleted in
their entirety and replaced with the following:
"(i) [Intentionally omitted].
(j) [Intentionally omitted]."
13. Section 4.2(c) of the Original Agreement shall be deleted in its
entirety and replaced with the following:
"(c) Consents and Waivers. The Seller shall have received copies of
all duly executed and delivered waivers and consents contemplated by
Section 2.2(d) and Schedule 2.2(d)-1 (except the Grumman Consent), all in
form and substance reasonably satisfactory to the Purchaser. Any
applicable waiting period under the HSR Act relating to the transactions
contemplated hereby shall have expired or been duly terminated."
14. Section 4.2(h) and (i) of the Original Agreement shall be deleted in
their entirety and replaced with the following:
"(h) [Intentionally omitted].
(i) [Intentionally omitted]."
15. Section 6.2 of the Original Agreement shall be deleted in its
entirety and replaced with the following:
<PAGE> 8
"6.2. Aggregate Liability. The aggregate liability of the Seller
under Article V or for any claim for any breach or violation of any
provision of this Agreement shall not exceed (i) the Purchase Price (as
adjusted pursuant to Section 1.2) minus (ii) the sum of the Put Price, if
any, and the BFM Put Price, if any, paid by the Seller or the Seller's
designee upon the exercise of the Put Right or the BFM Put Right."
16. The second to last sentence of Section 6.7 is hereby amended by
adding a reference to "3.11" immediately after the reference to "3.10" therein
and before the reference to "5.2" therein.
17. Except as provided herein, all provisions of the Agreement remain
unmodified and in full force and effect.
18. This Amendment may be executed in any number of counterparts, and
each such counterpart hereof shall be deemed to be an original instrument, but
all such counterparts together shall constitute but one agreement.
19. THIS AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH
THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO CONFLICT OF LAWS
PRINCIPLES.
<PAGE> 9
IN WITNESS WHEREOF, each of the parties has caused this Agreement
to be duly executed and delivered as of the day and year first above written.
GAS ENERGY INC.
By:__________________________________
Name:
Title:
GAS ENERGY COGENERATION INC.
By:__________________________________
Name:
Title:
THE BROOKLYN UNION GAS COMPANY
By:__________________________________
Name:
Title:
CALPINE EASTERN CORPORATION
By:___________________________________
Name:
Title:
CALPINE CORPORATION
By:___________________________________
Name:
Title:
<PAGE> 1
EXHIBIT 10.11.5
AMENDED AND RESTATED
COGENERATED ELECTRICITY
SALE AND PURCHASE AGREEMENT
BY AND BETWEEN
COGENRON INC,
AND
TEXAS UTILITIES ELECTRIC COMPANY
DATED JUNE 12,1985;
AS PREVIOUSLY AMENDED, AND
AS AMENDED AND RESTATED
ON DECEMBER 29, 1997
<PAGE> 2
INDEX TO AMENDED AND RESTATED CONGENERATED
ELECTRICITY SALE AND PURCHASE AGREEMENT BETWEEN
COGENRON INC. AND TEXAS UTILITIES ELECTRIC COMPANY
ARTICLE 1 - DEFINITIONS OF TERMS..............................................2
"Additional Backdown Energy"...........................................2
"Additional Energy Payment"............................................2
"Agreement"............................................................2
"Annual Excess Nonperformance Day".....................................3
"Available Capacity"...................................................3
"Available Energy".....................................................3
"Availability Plan"....................................................3
"Avoided Energy Costs".................................................3
"Backdown Energy"......................................................4
"CT's".................................................................4
"Capacity Curtailed"...................................................4
"Capacity Factor Performance Level"....................................4
"Capacity Payment".....................................................4
"Cogeneration Facility" or "Plant".....................................4
"Commercial Operating Date"............................................5
"Comparable Energy and Capacity".......................................5
"Contract Level" or "Contract Capacity"................................5
"Contract Rate"........................................................5
"Delivery Point" or "Point of Delivery"................................5
"Discount Energy"......................................................5
"ERCOT"................................................................5
"Energy Payment".......................................................5
"FERC".................................................................5
"Forced Outage"........................................................6
"Gas Price"............................................................6
"Hours Curtailed"......................................................6
"ISO"..................................................................6
"Incremental Lignite Energy Cost"......................................6
"Inadvertent Energy"...................................................7
"Intertie Equipment"...................................................7
"KW" or "kw"...........................................................7
"KWH" or "kwh".........................................................7
"MW" or "mw"...........................................................7
"MWH" or "mwh".........................................................7
"Net Energy"...........................................................7
"Off-Peak Hours".......................................................8
"Off-Peak Months"......................................................8
"Overstatement Event"..................................................8
"PSO"..................................................................8
"PUC"..................................................................8
"PURPA"................................................................8
<PAGE> 3
"Partial Nonperformance Day" or "PND"..................................8
"Partial Nonperformance Equation"......................................8
"Peak Excess Nonperformance Day".......................................8
"Peak Days"............................................................8
"Peak Hours"...........................................................8
"Peak Hour Partial Nonperformance Day" or "PHPND"......................8
"Peak Months"..........................................................9
"Plant Output".........................................................9
"Plant Output Condition"...............................................9
"Point of Interconnection".............................................9
"Primary Term".........................................................9
"Required Facilities"..................................................9
"Rolling Average"......................................................9
"Secondary Term".......................................................9
"Summer Peak Months"..................................................10
"Summer Excess Nonperformance Day"....................................10
"System Emergency" or "TU Electric System Emergency"..................10
"TGM".................................................................10
"TNP".................................................................10
"TNP Facilities"......................................................10
"TU Electric System"..................................................10
"Trail Operation".....................................................10
"Union Carbide Plant".................................................10
"VOM".................................................................10
"Winter Excess Nonperformance Day"....................................10
"Winter Peak Months"..................................................11
ARTICLE 2 - EFFECTIVE DATE; TERM.............................................11
2.1 Effective Date................................................11
2.2 Primary Term and Secondary Term...............................11
2.3 Option to Extend Secondary Term...............................11
ARTICLE 3 - SALE AND PURCHASE OF ENERGY AND CAPACITY.........................11
3.1 Agreement of Sale and Purchase................................11
3.2 Operation in Parallel.........................................16
3.3 Secondary Term Contract Level Modification....................16
3.4 Designation of Off-Peak and Peak Months.......................17
3.5 Restriction of Deliveries During Primary Term.................17
3.6 Capacity Payments During Primary Term.........................19
3.7 Delivery of Power During Primary Term.........................22
3.8 Capacity Payments During Secondary Term.......................22
3.9 Discount Energy; Inadvertent Energy...........................22
ARTICLE 4 - PAYMENTS.........................................................23
4.1 Total Payment During Primary Term.............................23
4.2 Capacity Payments During the Primary Term.....................23
ii
<PAGE> 4
4.3 Initial Energy Payments...................................... 24
4.4 Subsequent Energy Payments During the Primary Term........... 24
4.5 Incentive Energy Payments During the Primary Term............ 25
4.6 Reduced Energy Payments...................................... 25
4.7 Payment Obligations.......................................... 25
4.8 Energy Delivered During Trial Operations..................... 26
4.9 Payments During the Secondary Term........................... 26
ARTICLE 5 - METERING, BILLING AND PAYMENT............................ 33
5.1 Metering of Electrical Energy and Capacity................... 33
5.2 Monthly Metering............................................. 33
5.3 Inspection of Meters......................................... 34
5.4 Statement and Payment by TU Electric......................... 35
5.5 Interest on Overdue Payments................................. 35
ARTICLE 6 - INTERCONNECTION AND REQUIRED FACILITIES.................. 35
6.1 Information Regarding Equipment.............................. 35
6.2 Review of Information........................................ 36
6.3 Construction and Operation of Facility....................... 36
6.4 Permits...................................................... 36
6.5 Required Facilities.......................................... 36
6.6 Changes to Facilities........................................ 37
ARTICLE 7 - CONDITIONS OF SERVICE.................................... 37
7.1 Warranty by Cogenron......................................... 37
7.2 System Emergency............................................. 37
7.3 Disconnection................................................ 38
7.4 Deficiency or Excess of Deliveries to TNP.................... 38
7.5 Miscellaneous Conditions of Service.......................... 38
7.6 Duty to Use Good Faith: Gas Supply........................... 41
7.7 Duty to Inform............................................... 43
ARTICLE 8 - OWNERSHIP, INSTALLATION AND MAINTENANCE
OF EQUIPMENT......................................................... 43
8.1 Cost of Installation and Maintenance......................... 43
8.2 Ownership.................................................... 43
8.3 Cogenron's Liability......................................... 43
8.4 Costs Billed to Cogenron..................................... 43
ARTICLE 9 - INSPECTION AND ACCESS RIGHTS............................. 44
9.1 Access Rights................................................ 44
9.2 TU Electric Inspection....................................... 44
ARTICLE 10 - TERMINATION............................................. 44
10.1 Right to Terminate........................................... 44
10.2 Bankruptcy or Insolvency of TU Electric...................... 46
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<PAGE> 5
10.3 Disposition of Plant and Equipment.................................47
ARTICLE 11 - LIMITATION OF LIABILITY; PAYMENT ON TERMINATION; SUPPLY OF
COMPARABLE ENERGY AND CAPACITY; RECOUPMENT OF EARLY CAPACITY PAYMENT;
INDEMNITY...............................................................47
11.1 Limitation of Liability............................................47
11.2 Payment on Termination.............................................48
11.3 Supply of Comparable Energy and Capacity...........................49
11.4 Recoupment of Early Capacity Payment...............................50
11.5 Termination Other Than at End of Year..............................50
11.6 Indemnity..........................................................51
ARTICLE 12 - NO OPERATION IN INTERSTATE COMMERCE.............................52
12.1 Cogenerator Warranties.............................................52
12.2 Right to Suspend and Terminate.....................................52
12.3 Specific Performance...............................................53
12.4 Exceptions.........................................................53
ARTICLE 13 - NOTICE..........................................................54
13.1 Notices............................................................54
13.2 Change of Address..................................................55
ARTICLE 14 - LIABILITY; DEDICATION; SEVERAL OBLIGATIONS......................55
14.1 Liability..........................................................55
14.2 Dedication.........................................................55
14.3 Several Obligations................................................55
ARTICLE 15 - REPRESENTATIONS AND WARRANTIES OF THE RESPECTIVE PARTIES........56
15.1 Cogenron's Representations and Warranties..........................56
15.2 TU Electric's Representations and Warranties.......................57
15.3 Misrepresentation; Breach of Warranty; Fulfillment of Obligations..58
ARTICLE 16 - INSURANCE.......................................................59
16.1 Proof of Coverages.................................................59
16.2 Policies...........................................................59
16.3 Certificates.......................................................59
16.4 Limitation of Liability............................................60
16.5 Coverage and Limits of Liability...................................60
16.6 Release and Waiver.................................................60
ARTICLE 17 - TRANSMISSION SERVICE AGREEMENTS.................................61
17.1 Negotiation........................................................61
17.2 Transmission Service Charges.......................................61
17.3 Transmission of Comparable Energy and Capacity.....................62
17.4 Execution of Transmission Service Agreements.......................63
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<TABLE>
<S> <C>
ARTICLE 18 - FORCE MAJEURE ...................................................63
18.1 Definition............................................................63
18.2 Conditions Upon Force Majeure ".......................................64
18.3 Limitation of Term....................................................65
18.4 Further Limitation of Term............................................65
18.5 Additional Limitation of Term.........................................65
ARTICLE 19 - GOVERNMENTAL AND REGULATORY BODIES...............................65
ARTICLE 20 - PRIOR RIGHT TO PURCHASE OR LEASE IN PRIMARY TERM.................65
ARTICLE 21 - LEASE OPTION IN PRIMARY TERM.....................................66
ARTICLE 21A - RIGHT TO PURCHASE OR LEASE IN SECONDARY TERM....................67
ARTICLE 22 - WAIVER...........................................................68
ARTICLE 23 - NO RIGHTS OF THIRD PARTIES.......................................68
ARTICLE 24 - NO PARTNERSHIP...................................................68
ARTICLE 25 - SURETY AGREEMENT.................................................69
ARTICLE 26 - CONFIDENTIALITY AGREEMENT........................................69
ARTICLE 27 - ENTIRE AGREEMENT.................................................70
ARTICLE 28 - ASSIGNMENT.......................................................70
ARTICLE 29 - CAPTIONS.........................................................71
ARTICLE 30 - AMENDMENTS.......................................................71
ARTICLE 31 - CHOICE OF LAWS; VENUE............................................71
</TABLE>
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<PAGE> 7
AMENDED AND RESTATED
COGENERATED ELECTRICITY
SALE AND PURCHASE AGREEMENT
THIS AMENDED AND RESTATED COGENERATED ELECTRICITY SALE AND PURCHASE
AGREEMENT is executed as of the 29th day of December, 1997, by and between
COGENRON INC. ("Cogenron" or "Cogenerator"), a Delaware corporation with its
principal place of business located in Houston, Texas, with authority to do
business in the state of Texas, and TEXAS UTILITIES ELECTRIC COMPANY ("TU
Electric"), a Texas corporation with its principal place of business located in
Dallas, Texas, and is an amendment and restatement of that certain COGENERATED
ELECTRICITY SALE AND PURCHASE AGREEMENT, dated June 12,1985, between NORTHERN
COGENERATION ONE COMPANY, predecessor-in-interest to Cogenron, and TU Electric,
which agreement dated June 12, 1985 has been previously amended by a first
amendment, dated December 9, 1985; a second amendment, dated September 9, 1986;
a third amendment, dated December 4, 1986; a fourth amendment, dated May 28,
1987; a fifth amendment, dated June 19, 1987; a sixth amendment, dated December
10, 1987; and a seventh amendment, dated June 14, 1988; and which agreement
dated June 12, 1985, as previously amended, is hereby further amended as stated
in this Amended and Restated Cogenerated Electricity Sale and Purchase
Agreement, upon all of the terms and conditions set forth below.
WITNESSETH:
WHEREAS, Cogenron has constructed, owns and operates a Cogeneration
Facility, as defined herein, in Texas City, Texas; and
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<PAGE> 8
WHEREAS, Cogenron has been selling, and desires to continue to sell, and
TU Electric has been purchasing, and is willing to continue purchasing, electric
energy and capacity generated by said Cogeneration Facility;
NOW, THEREFORE, in consideration of the mutual covenants and promises
set forth below, together with other good and valuable consideration, the
receipt and sufficiency of which are hereby acknowledged by both Parties,
Cogenron hereby agrees to sell, and TU Electric hereby agrees to purchase,
electric energy and capacity generated by said Cogeneration Facility in
accordance with the terms of the Cogenerated Electricity Sale and Purchase
Agreement dated June 12, 1985, as previously amended, and as further amended and
restated in its entirety upon all of the following terms, conditions and
provisions.
ARTICLE I - DEFINITIONS OF TERMS
The following terms, when capitalized herein, shall have the definitions
set forth below.
"Additional Backdown Energy" means 200,000 megawatt hours in excess of
322,875 annual megawatt hours (calculated on an annual Rolling Average in
accordance with Section 3.5) of Backdown Energy, provided that such 322,875
figure shall be subject to change in the event that the Contract Level is
changed pursuant to Section 3.1 hereof, such figure to change proportionately
and simultaneously with any change in the Contract Level. This term only has
application during the Primary Term and does not apply during the Secondary
Term.
"Additional Energy Payment" means a $3,000 payment, one or more of which
may become payable in accordance with Section 3.1.2.
"Agreement" or "Cogeneration Agreement" or "Amended and Restated
Agreement" means this document including Exhibit "I" attached hereto, being the
calculation of Avoided Energy Costs
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<PAGE> 9
and schedule of energy payments due under Articles 4.3 and 4.4, Exhibit "II"
attached hereto, being a calculation of Energy Payments due under Article 4.5
hereof, and Exhibit "III" attached hereto, which consists of: (A) Surety
Agreement dated and effective June 12, 1985 between InterNorth, Inc. and Texas
Utilities Electric Company; (B) Letter dated July 17, 1985 executed by
InterNorth, Inc. and Texas Utilities Electric Company; (C) Letter dated May 24,
1988 executed by Enron Corp. and Texas Utilities Electric Company; and (D)
Consent and Assignment Agreement dated June 23, 1997 between Texas Utilities
Electric Company, Calpine Corporation and Enron Corp.
"Annual Excess Nonperformance Day" has the definition set forth in
Section 4.9.1(c).
"Available Capacity" has the definition set forth in Section 4.9.1(a).
"Available Energy" means the total generation output of the Cogeneration
Facility, less Cogenron's use of electricity in operating its generating
equipment.
"Availability Plan" means the latest plan provided by Cogenerator to the
PSO, as required herein, which is received by TU Electric before any direction
or request by TU Electric to operate the Plant in a different Plant Output
Condition. The Availability Plan must include: (i) hourly capacity available
from the Plant to TU Electric for the next business day and for any other day
prior to the next business day which is not a business day (transmitted to the
PSO by 8:00 a.m. of the preceding business day); (ii) changes in the level of
capacity available from the Plant to TU Electric within 15 minutes of any
change, and (iii) in the event of a full or partial outage that requires
repairs, the estimated time to complete the repairs and the amount of capacity
estimated to be available to TU Electric from the Plant after completion of the
repairs.
"Avoided Energy Costs" means those costs as calculated in accordance
with Exhibit I attached hereto.
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<PAGE> 10
"Backdown Energy" means, during the Primary Term, that number of
megawatts equal to (410 MW minus requested capacity) times hours of backdown
requested by TU Electric pursuant to Article 3.5.
"CT's" means combustion turbines, with "2-CT" referring to two
combustion turbines and "3-CT" referring to three combustion turbines.
"Capacity Curtailed" means, during the Primary Term, the difference
between the Net Energy being delivered by Cogenron's Cogeneration Facility at
the time of the request and the Net Energy actually delivered by Cogenron to the
Delivery Point during each of the Hours Curtailed.
"Capacity Factor Performance Level" means, during the Primary Term, except
as otherwise provided herein, the quotient, expressed as a percentage, of: (i)
the total amount of energy that Cogenron was able to deliver to TU Electric at
the Delivery Point during the applicable period, and divided by: (ii) the
product of the number of clock-hours for such period multiplied by Contract
Capacity.
"Capacity Payment" means the amount in dollars, resulting from the rates
specified herein, which will be paid for capacity subject to the provisions
hereof: (i) during the Primary Term, with respect to certain minimum Capacity
Factor Performance Levels and performance tests as specified in this Agreement,
less any other adjustment thereto, and (ii) during the Secondary Term, as
specified in Section 4.9, less any other adjustment thereto.
"Cogeneration Facility" or "Plant" means that electric generating
installation located immediately adjacent to the existing Union Carbide Plant in
Texas City, Texas, insofar as such electric generating installation is located
on Cogenron's side of the Point of Interconnection, excluding, however, all
Intertie Equipment.
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<PAGE> 11
"Commercial Operating Date" means May 1, 1987, which was the first day
when the Cogeneration Facility produced for 24 consecutive hours an hourly
kilowatt output equal to or greater than the Contract Level, which was
applicable as of such date.
"Comparable Energy and Capacity" means capacity and energy which
conforms in every respect to that capacity and energy which Cogenron is
obligated to deliver to TU Electric pursuant to this Agreement.
"Contract Level" or "Contract Capacity" means the amount of electrical
generating capacity, which amount Cogenron is obligated to supply to TU Electric
at the Delivery Point under the terms hereof, which amount is set by Section
3.1.1 hereof during the Primary Term and which is 435 MW, subject to adjustment
for performance tests as specified in this Agreement, for the Secondary Term.
"Contract Rate" means the monthly rate specified in Section 4.9.1 for a
particular month and subject to adjustment as set forth therein, expressed in
dollars per kilowatt. This applies only to the Secondary Term.
"Delivery Point" or "Point of Delivery" means those facilities on the TU
Electric System where energy and capacity generated by the Cogeneration Facility
is delivered hereunder to the TU Electric System.
"Discount Energy" means energy accepted by TU Electric as Discount
Energy as provided in Section 3.9, the price of which will be 98% of TU
Electric's decremental energy price as described in TU Electric's Rate LLP dated
May 16, 1994 or in subsequent versions of same tariff.
"ERCOT" means the Electric Reliability Council of Texas, including any
successor thereto or designees or subdivisions thereof
"Energy Payment" means the amount payable as provided in Article 4
hereof for Net Energy.
"FERC" means the Federal Energy Regulatory Commission.
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<PAGE> 12
"Forced Outage" means any unplanned outage that fully or partially
curtails the Net Energy being delivered to or requested by TU Electric of the
Cogeneration Facility.
"Gas Price" means the dollar amount for the fuel component used in the
calculation of the Energy Payment during the Secondary Term and will equal:
(i) if a gas supply contract that is mutually acceptable to both
Cogenron and TU Electric has been executed in accordance with
Section 7.6 of this Agreement, the price per MMBtu specified in
such gas supply contract;
(ii) if TU Electric elects to supply gas during the Secondary Term
pursuant to Section 7.6, the price will be $0.00; and
(iii) if a gas supply contract mutually acceptable to both Cogenron and
TU Electric has not been executed by Cogenron in accordance with
Section 7.6, the price for the fuel component in each such month
will be (until the Parties agree otherwise in writing) the amount
of actual direct costs incurred by Cogenron per MMBtu to perform
its obligations under this Agreement.
"Gas Price" does not apply during the Primary Term.
"Hours Curtailed" means, during the Primary Term, those hours for which
TU Electric has requested and received reduced energy deliveries from Cogenron,
not including hours reduced for spinning reserve.
"ISO" means the ERCOT Independent System Operator, whose duties are
defined in the ERCOT Operating Guide.
"Incremental Lignite Energy Cost" means the incremental fuel cost of TU
Electric of generation on lignite fuel which, but for the purchase of energy
from the Cogeneration Facility, TU
6
<PAGE> 13
Electric would have incurred had TU Electric been required to generate itself.
Capacity costs are not included in this definition. This applies only to the
Primary Term.
"Inadvertent Energy" means any energy received by TU Electric during
Plant Output Conditions C or D as set forth in Section 4.9.2 in excess of the
respective MW levels set in Section 4.9.2 for Plant Output Conditions C or D,
provided TU Electric did not exercise the option to accept Discount Energy
pursuant to Section 3.9. This applies only to the Secondary Term.
"Intertie Equipment" means any and all metering equipment, regardless of
whether said equipment is located on the Cogenron side or the TNP side of the
Point of Interconnection, including any equipment necessary to telemeter output
information, and all intertie relaying facilities deemed necessary by TNP to
protect its facilities, to be installed hereunder for the purpose of operating
the Cogeneration Facility in parallel with the TNP Facilities, the TU Electric
System and any utility connected therewith.
"KW or "kw" means one kilowatt or 1000 watts of electricity.
"KWH" or "kwh" means one kilowatt-hour of electricity.
"MW" or "mw" means one megawatt or 1000 kilowatts of electricity.
"MWH" or "mwh" means one megawatt-hour or one thousand kilowatt-hours of
electricity.
"Net Energy" means, during the Primary Term, the Available Energy
generated by the Cogeneration Facility, less that energy consumed in the
operation of the Union Carbide Plant. "Net Energy" means during the Secondary
Term, the Available Energy generated by the Cogeneration Facility less and
except: (i) Discount Energy (as defined in Section 3.9); (ii) Inadvertent Energy
(as defined in Section 3.9); and (iii) such energy, if any, that is not required
by TU Electric pursuant to Section 3.1.2 and that is sold by Cogenron in
accordance with the terms of this Agreement and on
7
<PAGE> 14
a nonfirm and interruptible basis to any other third parties, including any
energy sold for the Union Carbide Plant.
"Off-Peak Hours" means all hours of the year not designated as Peak
Hours.
"Off-Peak Months" means those months not designated as Peak Months.
"Overstatement Event" has the definition set forth in Section 4.9.1(g).
"PSO" means the Power Supply Operations group, an organizational unit of
TU Electric.
"PUC: means the Public Utility Commission of Texas.
"PURPA" means the federal Public Utility Regulatory Policies Act of
1978, 16 U.S.C. Section 2601, et seq., as amended.
"Partial Nonperformance Day" or "PND" has the definition set forth in
Section 4.9.1(a).
"Partial Nonperformance Equation" has the meaning and calculation set
forth in Section 4.9.1(a).
"Peak Excess Nonperformance Day" has the definition set forth in Section
4.9.1(d).
"Peak Days" means all days except Saturdays and Sundays in June, July,
August and September, together with all days in December, January and February.
"Peak Hours" means the hours on Monday through Friday, from 8:00 a.m. to
10:00 p.m., local Dallas time, during the months of June, July, August and
September, and each day, 5:00 a.m. to 10:00 p.m., local Dallas time during the
months of December, January and February; provided that different months may be
designated by TU Electric from time to time pursuant to Article 3.4 hereof,
except neither the total number of Peak Hours nor Peak Months may be increased.
"Peak Hour Partial Nonperformance Day" ' or "PHPND" has the definition
set forth in Section 4.9.1(a).
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<PAGE> 15
"Peak Months" means the seven calendar months January, February, June,
July, August, September and December of each calendar year, provided that
different months may be designated by TU Electric from time to time pursuant to
Article 3.4 hereof.
"Plant Output" means the number of MW which the Plant will generate and
which will be available for transmission when operating in a particular Plant
Output Condition.
"Plant Output Condition" means the condition directed by TU Electric for
Plant Output of the Cogeneration Facility, which Plant Output Conditions are
described as A through E in Section 4.9.2.
"Point of Interconnection" means that point at which the Cogeneration
Facility is electrically interconnected with the TNP Facilities where TNP's
service wires are connected to Cogenron's service wires.
"Primary Term" means that period from June 12, 1985 to midnight, on June
30, 1999.
"Required Facilities" means all equipment and facilities furnished and
owned by TU Electric which are necessary to reliably and safely receive
Cogenron's power and energy into the TU Electric System.
"Rolling Average" means a numeric calculation which is comprised of data
for a specific number of consecutive time periods, which data is summed and
divided by the number of specific time periods included in such average. The
calculation is "rolling" inasmuch as, for each successive rolling average
calculation, data for the earliest time period in the series is deleted while
data for the latest time period in the series is added, as such data becomes
available from time to time.
"Secondary Term" means that period from midnight on June 30, 1999, to
midnight on September 30, 2002.
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<PAGE> 16
"Summer Peak Months" are June, July, August and September, unless
modified otherwise as provided herein.
"Summer Excess Nonperformance Day" has the definition set forth in
Section 4.9.l(e).
"System Emergency" or "TU Electric System Emergency" means any condition
which is declared to be an emergency by TU Electric, the ISO or ERCOT, or any
designee thereof, which may disrupt service to customers or endanger life or
property.
"TGM" means the Transmission Grid Management group, an organizational
unit of TU Electric Company.
"TNP" means Texas-New Mexico Power Company.
"TNP Facilities" means all of the facilities of TNP which are used to
transmit the energy and capacity from Cogenron's Cogeneration Facility to the
Transmission Service Providers for delivery to the TU Electric System.
"TU Electric System" means all of the TU Electric electric facilities,
system, and appurtenances.
"Transmission Service Providers" means those utilities transmitting
energy and power delivered hereunder.
"Trial Operation" means the operation of the Cogeneration Facility which
occurred prior to the Commercial Operating Date.
"Union Carbide Plant" means that presently existing plant owned by Union
Carbide Corporation and located in Texas City, Texas.
"VOM" means Cogenerator's variable operations and maintenance charge for
the Cogeneration Facility, which, throughout the Secondary Term, is deemed to be
$1.80 per MWH.
"Winter Excess Nonperformance Day" has the definition set forth in
Section 4.9.1(f).
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<PAGE> 17
"Winter Peak Months" are January, February and December, unless modified
otherwise as provided herein.
ARTICLE 2 - EFFECTIVE DATE; TERM
2.1 Effective Date. This Amended and Restated Agreement became effective
as of June 12, 1985.
2.2 Primary Term and Secondary Term. Unless otherwise terminated in
accordance with the terms hereof, this Amended and Restated Agreement shall
remain in full force and effect for its Primary Term from June 12, 1985 to
midnight, on June 30, 1999, and then shall continue thereafter into its
Secondary Term from midnight on June 30, 1999 and ending at midnight, on
September 30, 2002.
2.3 Option to Extend Secondary Term. TU Electric and Cogenron shall have
the option to extend the Secondary Term beyond September 30, 2002; provided that
the Parties are able to agree upon the terms and conditions thereof; and,
provided further, that such extension shall be subject to both Cogenron and TU
Electric obtaining like extensions from third parties, including, without
limitation, any Transmission Service Providers, of all other contracts and
agreements necessary and incident to the proposed extension, and TU Electric and
Cogenron hereby agree to use all reasonable efforts in obtaining such extensions
from third parties.
ARTICLE 3 - SALE AND PURCHASE OF ENERGY AND CAPACITY
3.1 Agreement of Sale and Purchase. Pursuant to the terms hereof,
Cogenron agrees to sell and deliver, and TU Electric agrees to purchase and
accept, at the Point of Delivery specified herein, the Net Energy generated by
the Cogeneration Facility. The Net Energy to be sold and
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<PAGE> 18
purchased during the Primary Term shall be governed by Section 3.1.1 hereof;
the Net Energy to be sold and purchased during the Secondary Term shall be
governed by Section 3.1.2 hereof.
3.1.1 Primary Term. During the Primary Term of this Agreement,
Cogenron shall not sell electrical capacity and energy from the
Cogeneration Facility other than to TU Electric and the amount of
electrical capacity and energy which Cogenron is presently and has been
committed to sell for use in the Union Carbide Plant. Subject to the
other terms contained herein, throughout the Primary Term, Cogenron will
have available and deliver, or cause to be delivered, to the Point of
Interconnection capacity and energy for redelivery to TU Electric, and
TU Electric will receive and pay for, capacity and energy of the
Cogeneration Facility at the Contract Level of 410 MW, as adjusted as
provided below in this Section 3.1.1. Such Contract Level amount shall
be determined by a 24-hour performance test, with the results to be
temperature-adjusted (pursuant to manufacturer's specifications) to 91
degrees F at site conditions and adjusted for any capacity reduction due
to line losses. That test shall be performed in accordance with Sections
6 and 22 of the American Society of Mechanical Engineers Power Test
Codes, latest edition, or International Standards Organization Standard
2314. Cogenron shall allow representatives of TU Electric to be present
for such test. Such Contract Level amount may be redetermined by a
24-hour performance test as often as once each calendar quarter, at TU
Electric's election, using data from in-place station meters.
Instrumentation error allowable during testing shall be in accordance
with ANSI B 133.6. The cost of all such performance tests shall be borne
by Cogenron.
3.1.2 Secondary Term. During the Secondary Term, the Net Energy
to be sold by Cogenron and purchased by TU Electric will be dependent
upon the Plant Output Condition then directed by TU Electric, and
Cogenron agrees to operate the Cogeneration Facility at
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<PAGE> 19
the Plant Output Condition directed by TU Electric, except that Cogenron
may elect to operate the Cogeneration Facility at a higher level than
directed by TU Electric for the sale of interruptible and nonfirm energy
to third parties (including any such sales for the Union Carbide
Plant), subject to TU Electric's rights herein. TU Electric has the
continuing right to direct Cogenron to operate, and Cogenron agrees to
operate upon such direction, the Plant to the maximum Plant Output
whenever the Plant is operating in the 2-CT mode, and to request
Cogenron to operate the Plant to produce Plant Output at a level above
435 MW whenever the Plant is in the 3-CT operation mode, and in either
case, the Energy Payment will include an incentive as shown on the
Energy Payment table as set forth in Section 4.9.2 of this Agreement.
Cogenron shall have no obligation to provide TU Electric with output
above 435 MW, but may comply with TU's request at Cogenron's election.
Throughout the Secondary Term, TU Electric will, at all times, have the
continuing right to direct firm sales to TU Electric of up to 435 MW of
Net Energy from the Cogeneration Facility, and, to the extent that
Cogenron is selling any energy from the Cogeneration Facility to third
parties, such third party sales (including any such sales for the Union
Carbide Plant) will be interruptible and nonfirm to the extent that TU
Electric requires deliveries of any energy pursuant to this Agreement up
to a level of 435 MW. If Cogenron elects to make any third party sales
(including any such sales for the Union Carbide Plant), Cogenron will be
responsible for any ancillary services (including scheduling) and
transmission services necessary or desirable in connection with such
sales and will be responsible for any applicable ERCOT ISO services,
fees and charges.
The. minimum or normal Plant Output for the Cogeneration
Facility for the various Plant Output Conditions are specified in the
table set out in Section 4.9.2 of this Agreement.
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<PAGE> 20
TU Electric has the continuing right to direct Cogenron to operate, and
Cogenron agrees to operate, upon such direction, the Plant in a 2-CT
mode Plant Output Condition from time to time throughout the Secondary
Term; provided that, Cogenron will not be obligated to actually take
the Plant from a 3-CT mode Plant Output Condition and operate the Plant
in a 2-CT mode Plant Output Condition, upon TU Electric's direction,
more than 52 times annually unless agreeable to Cogenron in its sole
discretion. TU Electric may direct the Plant from a 3-CT mode Plant
Output Condition to 2-CT mode Plant Output Condition fifteen (15) times
annually for no additional payment, and TU Electric will pay $3,000 as
an energy-related payment (an "Additional Energy Payment") each time TU
Electric directs the Plant from a 3-CT mode Plant Output Condition to
2-CT mode Plant Output Condition in excess of fifteen times per calendar
year; provided that, Cogenron actually takes the Plant from an operating
3-CT mode Plant Output Condition and operates the Cogeneration Facility
in a 2-CT mode Plant Output Condition in accordance with TU Electric's
direction. If, upon direction by TU Electric, Cogenron does not actually
take the Plant from an operating 3-CT mode Plant Output Condition and
operate the Cogeneration Facility in a 2-CT mode Plant Output Condition
in accordance with TU Electric's direction, then, regardless of whether
Cogenron is making third party sales, TU Electric will pay for energy in
accordance with Section 4.9.2 and TU Electric's direction to the 2-CT
Plant Output Condition will not be counted as one of the 52 annual
maximum or 15 annual times at no cost that TU Electric may direct the
Plant from a 3-CT mode Plant Output Condition to 2-CT mode Plant Output
Condition.
Each time that TU Electric directs Cogenron to take the Plant
from a 3-CT mode Plant Output Condition to 2-CT mode Plant Output
Condition, TU Electric will determine
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<PAGE> 21
the duration of time at which the Plant will operate in the specified,
or any other, 2-CT Plant Output Condition, which will be for a minimum
of six hours and a maximum of sixty hours each time TU Electric directs
Cogenron to take the Plant from an operating 3-CT mode Plant Output
Condition to 2-CT mode Plant Output Condition; and, if Cogenerator
actually takes the Plant from an operating 3-CT mode Plant Output
Condition to 2-CT mode Plant Output Condition, then Cogenron will not be
obligated to operate the Plant in a 3-CT mode Plant Output Condition
prior to termination of the period specified by TU Electric, provided
that: (i) at any time after the Plant has operated in one or more 2-CT
mode Plant Output Conditions for an aggregate period of four hours, TU
Electric may, upon two-hours' notice, direct Cogenron to operate in a
3-CT mode pursuant to Plant Output Condition A or C, or request Cogenron
to operate in the 3-CT mode pursuant to Plant Output Condition B; and
(ii) TU Electric may request, prior to the four-hour minimum period set
forth in (i) of this subsection, that Cogenron operate in a 3-CT mode
pursuant to Plant Output Condition A, B or C and Cogenerator will, if
Plant operations allow, operate the Plant in the requested 3-CT mode
Plant Output Condition; provided further that, at any time during which
TU Electric directs Cogenron to take the Plant from a 3-CT mode Plant
Output Condition to 2-CT mode Plant Output Condition, and Cogenron
actually takes the Plant from a 3-CT mode Plant Output Condition and
operates the Plant in a 2-CT mode Plant Output Condition, Cogenerator
may request a maintenance window of twelve (12) hours or less and if, in
the sole judgment of TU Electric, such a maintenance window will not
affect the system operations of TU Electric, then: (a) TU Electric will
approve Cogenerator's request to proceed with the maintenance; (b) to
the degree that the approved maintenance would reduce the Available
Capacity, that reduction in Available Capacity will not be included in
the PND
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<PAGE> 22
or PHPND calculation in the Partial Nonperformance Equation; and (c) TU
Electric may request that Cogenron operate in a 3-CT mode Plant Output
Condition during the approved maintenance window, but Cogenerator is not
obligated to operate the Plant in a 3-CT mode Plant Output Condition
until the end of the approved maintenance window.
3.2 Operation in Parallel. Cogenron shall operate the Cogeneration
Facility in parallel with the TNP Facilities, the TU Electric System,
together with any utility connected therewith, and any Transmission
Service Providers required for transmission.
3.3 Secondary Term Contract Level Modification. During the Secondary
Term, a 24-hour performance test may be performed at TU Electric's election, as
often as once each calendar quarter, and the cost of all such performance tests
will be borne entirely by Cogenron. Unless the Parties mutually agree in writing
otherwise, each 24-hour performance test will be temperature-adjusted (pursuant
to manufacturer's specifications) to 91 degree F at site conditions and adjusted
for any capacity reduction due to line losses. Unless the Parties mutually agree
in writing otherwise, the results of each test will be performed in accordance
with Sections 6 and 22 of the American Society of Mechanical Engineers Power
Test Codes, latest edition, or International Standards Organization Standard
2314, and instrumentation error allowable during testing will be in accordance
with ANSI B 133.6. Cogenron will allow TU Electric representatives to be present
for each such test. If the results of any such performance test indicate that
the Plant is not capable of delivering capacity and energy to the Point of
Interconnection at the Contract Level then in effect, the Contract Level will be
reduced accordingly, effective as of the first day of the month in which the
test was performed; provided that, if any such performance test indicates that a
reduction in the Contract Level should be effected, then Cogenron may request
and conduct, at Cogenron's sole expense, within ten days of the prior test an
additional 24-hour performance test(s), as may be necessary, which will be
conducted
16
<PAGE> 23
in the manner set forth above. Cogenron will give TU Electric reasonable advance
notice so that TU Electric may have a representative present during such test.
If the additional performance test(s) indicates that the Plant is capable of
delivering capacity and energy to the Point of Interconnection at a level higher
than the previous test, then the Contract Level will be adjusted to such higher
level, but in no event greater than 435 MW, effective as of the first day of the
month in which the test was performed.
3.4 Designation of Off-Peak and Peak Months. Upon six (6) months notice
to Cogenron, TU Electric may change the designation of a Peak Month as defined
herein to an Off-Peak Month and vice-versa. In no event shall the number of Peak
Months exceed seven in any one calendar year. Peak Hours shall occur only during
Peak Months.
3.5 Restriction of Deliveries During Primary Term. During the Primary
Term, to assist TU Electric in maintaining TU Electric System operating
flexibility, Cogenron agrees to restrict its hourly energy delivery as follows:
TU Electric may require Cogenron to reduce energy deliveries to TU Electric from
said Cogeneration Facility up to, but not to exceed, 15 MW for each of
Cogenron's gas turbines in the Cogeneration Facility. If, in TU Electric's
opinion, additional reductions are required, TU Electric may require that the
output of the Cogeneration Facility be reduced further to as low as 234 MW. The
aforementioned reduction may be imposed by TU Electric upon four hours' notice
at any time, and from time to time, during the Primary Term, but shall be
limited to an annual aggregate of 322,875 MWH, calculated on an annual Rolling
Average, and subject to any change to the Contract Level made pursuant to
Section 3.1, with the annual aggregate changing proportionately and
simultaneously with any change in the Contract Level. The calculation of said
reduced energy deliveries shall be made by hourly determinations of the
difference between the actual Net Energy delivered by Cogenron's Cogeneration
Facility at the time of TU Electric's request for reduction and
17
<PAGE> 24
the Net Energy actually delivered by Cogenron to the Delivery Point. Should TU
Electric restrict Cogenron's facility to as low as a 234 MW output, such
restriction shall last a minimum of four hours unless Cogenron agrees to a
shorter time period. In no event shall Cogenron be required to reduce its power
output to less than 234 MW, except in instances of System Emergencies.
3.5.1 Beginning on January 1, 1989 and ending on December 31, 1993,
TU Electric shall have the option to request an additional 200,000 MWH per
year of Additional Backdown Energy provided that the plant output is not
reduced to less than 234 MW by such a request and that such restrictions
shall last a minimum of four hours unless Cogenron agrees to a shorter time
period.
3.5.2 During the Primary Term, when requesting a restriction of
deliveries or Additional Backdown Energy, TU Electric may, at its option,
inform Cogenron of an energy price at which TU Electric is willing to
accept the energy (TU Electric's "Incremental Price"). That price shall be
based on 98% of TU Electric's Incremental Energy Cost but not less than TU
Electric's Incremental Lignite Energy Cost. Cogenron then has the option of
either accepting the requested load reduction or continuing to generate
energy and accepting TU Electric's Incremental Price for energy delivered
to TU Electric that would not have been delivered had the requested load
reduction been accepted. In the event Cogenron elects to continue to
generate, all incremental energy delivered to and paid for by TU Electric
at TU Electric's Incremental Price shall be considered as reductions for
the purpose of determining the allowable MWH of reduction in Section 3.5.
3.5.3 Notwithstanding anything to the contrary contained herein, TU
Electric shall have the right to request Additional Backdown Energy at any
time and from time to time during the Primary Term, and Cogenron shall
comply with such request if it can be
18
<PAGE> 25
accomplished, in the opinion of Cogenron, without violating any other agreement
which Cogenron has entered into in order to meet its obligations under this
Agreement.
3.6 Capacity Payments During Primary Term. During the Primary Term,
except as otherwise provided herein, and subject to the other terms hereof, TU
Electric agrees to make Capacity Payments to Cogenron in connection with said
Cogeneration Facility, with the applicable rates being specified in Article 4.2
below. For a period beginning on the Commercial Operating Date and ending after
the expiration of six (6) full calendar months after the Commercial Operating
Date, for the purposes of this Agreement: (i) the applicable twelve month
Rolling Average Capacity Factor shall be deemed to be equal to 65.00%, (ii) the
applicable seven month Peak Rolling Average Capacity Factor shall be deemed to
be equal to 75.00%, and (iii) the applicable Peak Rolling Average Capacity
Factor shall be deemed to be equal to 85.00%. After the expiration of six (6)
full calendar months after the Commercial Operating Date, if any one of
Cogenerator's Rolling Average Capacity Factors, calculated on the basis of the
average Capacity Factor Performance Levels achieved by Cogenerator in such
previous six (6) months, fails to be equal to, or to exceed, the corresponding
deemed Capacity Factor specified above, then an adjustment to the previous
Capacity Payments shall be made. The adjustment shall equal the
difference between: (i) each of the Capacity Payments actually made and (ii) the
capacity payments that would have been made if no Capacity Factors had been
deemed pursuant to this Section. Any such adjustment shall bear interest at the
commercial paper rate charged from time to time by NationsBank in Dallas, Texas
from the end of the sixth full calendar month after the Commercial Operating
Date and shall be repayable in twelve (12) equal monthly installments beginning
on the last day of the sixth full calendar month after the Commercial Operating
Date. Additional months (beginning with the seventh and eighth months) will be
added to the selected initial period until such time as a twelve-month Rolling
Average, a seven-month Peak
19
<PAGE> 26
Rolling Average and an Peak Hour Rolling Average Capacity Factor Performance
Level can each be determined. Rolling Averages established beginning in the
seventh month shall be utilized to determine whether minimum Capacity Factor
Performance Levels have been maintained at the levels required in order for
Cogenron to receive the full amount of the Capacity Payments at rates specified
in Article 4.2. A seven-month Peak Rolling Average Capacity Factor Performance
Level of 75%, an Peak Hour Rolling Average Capacity Factor Performance Level of
85% and a twelve (12) month Rolling Average Capacity Factor Performance Level of
65%, calculated as specified by the equations below, must each be maintained at
all times in order for Cogenron to receive the full amount of applicable
Capacity Payments. Any restriction of deliveries, as specified in Article 3.5,
which occur will be included in such calculation as the product of Capacity
Curtailed and Hours Curtailed, calculated into the applicable formula as
follows:
SEVEN-MONTH PEAK ROLLING AVERAGE CAPACITY FACTOR:
= Net Energy During Peak Months + (Hours Curtailed x Capacity Curtailed)*
-----------------------------------------
Contract Capacity x Hours in Peak Months
PEAK HOURS (DURING THE MOST RECENT FOUR MONTHS CONTAINING PEAK HOURS) ROLLING
AVERAGE CAPACITY FACTOR:
= Net Energy During Peak Hours + (Hours Curtailed x Capacity Curtailed)**
-----------------------------------------------
Contract Capacity x Peak Hours
TWELVE-MONTH ROLLING AVERAGE CAPACITY FACTOR DURING 1987 AND 1988 ONLY:
= Net Energy During Last + (1/2 (Hours Curtailed x Capacity Curtailed))
Twelve (12) Months -----------------------------------------------
Contract Capacity x Hours in Last Twelve
(12) Months
Twelve-month Rolling Average Capacity Factor after 1988 until the end of the
primary term:
= Net Energy During Last Twelve (12) Months + (Additional Backdown Energy)
----------------------------
Contract Capacity Multiplied
by the Period Hours.
* During Peak Months
** During Peak Hours
20
<PAGE> 27
Each such Capacity Factor Performance Level as calculated above shall be
multiplied times 100 to calculate the Capacity Factor Performance Level in
percent, with such calculation being expressed to the nearest one hundredth of a
percent. Should the seven-month Peak Capacity Factor Performance Level at the
end of any month be less than 75%, a Capacity Payment adjustment will be made
which reduces that month's Capacity Payment 4% for each percentage point below
80%. In addition, should the Peak Hour Rolling Average Capacity Factor
Performance Level be less than 85% at the end of any month, a Capacity Payment
adjustment will be made which reduces said month's Capacity Payment 4% for each
percentage point below the 85% minimum Peak Hour Rolling Average Capacity Factor
Performance Level. Should Cogenron, in any month, fail to meet both the 75%
seven month Peak Capacity Factor Performance Level and the 85% Peak Hour Rolling
Average Capacity Factor Performance Level, the reduction of Cogenron's Capacity
Payment for that month shall be the greater of the two as the case may be,
required Capacity Payment reductions or eliminations. If the twelve (12) month
Rolling Average Capacity Factor Performance Level at the end of any month is
less than 65%, Cogenron shall receive no Capacity Payment for that month
irrespective of Cogenron's meeting the seven month Peak Capacity Factor
Performance Level and/or the Peak Hour Rolling Average Capacity Factor
Performance Level for that month.
Notwithstanding anything to the contrary contained herein, in the event
that Cogenron fails to deliver, due solely to fuel unavailability, in any
seventy-two (72) hour period, ninety percent (90%) of the Contract Level, or 90%
of any lower capacity level requested by TU Electric, and such failure is
without the prior written approval of TU Electric, Cogenron agrees to payment
reductions from TU Electric as follows:
(a) for the first two hours, consecutive or nonconsecutive, the
payment reduction will be five percent (5%) of the next Capacity Payment
(unadjusted);
21
<PAGE> 28
(b) for the second two hours, consecutive or nonconsecutive, the
payment reduction will be two and one-half percent (2.5%) of the next
Capacity Payment (unadjusted);
(c) for each additional one hour, whether consecutive or
nonconsecutive, the payment reduction will be one percent (1%) of the
next Capacity Payment (unadjusted); provided that, should the next
Capacity Payment (unadjusted) be entirely forfeited by the payment
reduction provided herein, such payment reduction shall apply to later
Capacity Payments until all payment reductions have been paid.
It is further agreed that such payment reductions shall be liquidated
damages and not penalties.
3.7 Delivery of Power During Primary Term. Cogenerator shall at any
time, upon TU Electric's request, increase deliveries of energy up to a maximum
rate of delivery equal to the Contract Capacity plus required spinning reserve,
except to the extent that such energy is unavailable because of Force Majeure,
Forced Outage or scheduled maintenance.
3.8 Capacity Payments During Secondary Term. Payments by TU Electric to
Cogenron during the Secondary Term shall be governed by Article 4 hereof.
3.9 Discount Energy; Inadvertent Energy. During the Secondary Term, when
TU Electric directs Plant Output to Plant Output Conditions C or D as set forth
in Section 4.9.2, TU Electric may, at its option, inform Cogenron that TU
Electric is willing to accept a quantity of energy as specified by TU Electric
in excess of the MW level provided for the Plant Output Conditions directed by
TU Electric (such excess energy being "Discount Energy"). The price for Discount
Energy will be 98% of TU Electric's decremental energy price which is made after
the fact on an hourly basis using TU Electric's economic dispatch model and is
further described in TU Electric's Rate LPP dated May 16, 1994 or any subsequent
tariff that replaces Rate LPP. In addition, if TU Electric does
22
<PAGE> 29
not exercise the option to accept Discount Energy, then any energy received by
TU Electric during Plant Output Conditions C or D as set forth in Section 4.9.2
in excess of the MW levels for Plant Output Conditions C or D set forth in
Section 4.9.2 (such excess energy being "Inadvertent Energy") will be paid for
at the same price as Discount Energy; provided that, any Inadvertent Energy
received by TU Electric in excess of 5% of the MW level for the Plant Output
Condition specified by TU Electric will be sold and delivered by Cogenron to TU
Electric at no cost or charge to TU Electric and will result in no payment from
TU Electric for such portion in excess of 5% of the MW level specified for such
Plant Output Condition in Section 4.9.2.
ARTICLE 4 - PAYMENTS
4.1 Total Payment During Primary Term. The total payment by TU Electric
to Cogenron for the Net Energy delivered by Cogenron, and for the capacity of
the Cogeneration Facility made available by Cogenron to TU Electric, shall be
the sum of the Capacity Payment, less transmission facility and/or charges by
Transmission Service Providers, or any other party or entity, and the Energy
Payment, equal to the Net Energy, which makes provision for line losses, any
repayments to Transmission Service Providers for line losses or for charges for
line losses, and less any other reductions pursuant to the terms hereof, such
reductions to be effective up to January 1, 1997. Commencing with January 1,
1997, reduction from payments due to transmission facility and/or service
charges shall be made by TU Electric in accordance with Article 17 hereof.
4.2 Capacity Payments During the Primary Term. Subject to the other
terms hereof, including, but not limited to, Articles 3.5 and 3.6 above, the
applicable rates for calculation of Capacity Payments will be as follows for the
indicated calendar years:
23
<PAGE> 30
<TABLE>
<CAPTION>
$ Per KW
Year Per Month
---- ---------
<S> <C>
1987 $ 3.17
1988 4.50
1989 15.10
1990 16.86
1991 17.16
1992 17.67
1993 18.15
1994 18.63
1995 19.10
1996 19.64
1997 20.15
1998 20.42
*1999 (first half) 22.19
</TABLE>
* First half is January 1 to June 30.
The Capacity Payment will be equal to the applicable rate per kilowatt
as specified above multiplied by the applicable Contract Level, less any
adjustments thereto made pursuant to Article 3.6 above.
4.3 Initial Energy Payments. [Deleted.]
4.4 Subsequent Energy Payments During the Primary Term. Commencing with
calendar year 1989 and continuing until the end of the Primary Term, monthly
Energy Payments for Net Energy delivered which is equal to or less than 70% of
the hours in such month multiplied by the applicable Contract Level specified in
Article 3.1 will be based on the Avoided Energy Cost as specified on Page 2 of
Exhibit I attached hereto. Any Net Energy delivered from the Cogeneration
Facility in excess of (Contract Capacity x Hours in the Month x .7) minus MWH of
Additional
24
<PAGE> 31
Backdown Energy for that month, which is not priced based on the criteria set
forth in Article 4.5, shall be priced as set forth on Page 2 of Exhibit 1.
4.5 Incentive Energy Payments During the Primary Term. Commencing with
January 1, 1989 and continuing until the end of the Primary Term, Cogenron will
be paid for Net Energy delivered which is in excess of (Contract Capacity x
Hours in the Month x .7) minus MWH of Additional Backdown Energy in the
corresponding month based on TU Electric's weighted average cost of gas
calculated by the formula shown in Exhibit II, provided both of the following
two criteria are met:
(i) the twelve-month Rolling Average Capacity Factor Performance
Level must be greater than 70%; and
(ii) the current month Capacity Factor Performance Level must be
greater than 70%.
Should either of such criteria not be met, then any energy above said
70% level delivered during said month shall be priced as set forth on Page 2 of
Exhibit I.
4.6 Reduced Energy Payments. [Deleted.]
4.7 Payment Obligations. The Parties are of the opinion that the
capacity and energy rates set forth herein as to both the Primary Term and the
Secondary Term are not subject to alteration by any court or regulatory
authority, including, without limitation, the PUC. If, however, at any time
during the Primary Term or Secondary Term of this Agreement, any court or
regulatory authority, other than in response to a proceeding initiated by TU
Electric for the purpose of requesting or obtaining such disallowance, and after
opportunity for Cogenron to protest, alters the prices for energy and capacity
purchases by TU Electric from Cogenron under this Agreement, or the payments
resulting from those prices, or the ability of TU Electric to recover payments
under this
25
<PAGE> 32
Agreement from the customers served by TU Electric on a current, monthly basis,
then any such payments (or portion thereof) hereunder in excess of such amounts
allowed by such court or regulatory authority shall be (effective from the date
of such order, and remaining in effect throughout the term hereof or the
effective date of any subsequent order) deleted from the payments which would
otherwise apply hereunder, provided that, during the Secondary Term only, if the
prices or payments are altered in such manner, then TU Electric will within 30
days after such judgment or order becomes final and non-appealable, provide
Cogenron with written notice of its election, at its sole option, to either: (a)
continue to pay the full price and payments provided in this Agreement, or (b)
to pay the reduced prices or payments resulting from the alteration by the court
or regulatory authority. If the price or payments are altered and TU Electric
elects to pay the reduced price or payments in accordance with clause (b) of the
preceding sentence, then Cogenron, at its sole election may, within 30 days
after receiving notice from TU Electric, terminate this Agreement upon thirty
days written notice. However, any sums initially recouped from TU Electric's
ratepayers in either the Primary Term or the Secondary Term, but which are
subsequently disallowed by the PUC and charged back to TU Electric, shall not be
set-off or credited against subsequent payments made by TU Electric for energy
purchased hereunder from Cogenron, except for the last 30 days included in the
period of such disallowance.
4.8 Energy Delivered During Trial Operations. [Deleted.]
4.9 Payments During the Secondary Term. During the Secondary Term, the
total consideration that TU Electric is obligated to pay for all capacity and
energy delivered will consist of Capacity Payments, Energy Payments and, if any,
Additional Energy Payments. During the Secondary Term, Capacity Payments and
Energy Payments will be determined as follows:
26
<PAGE> 33
4.9.1 Capacity Payments. During the Secondary Term, monthly Capacity
Payments shall be calculated by multiplying the Contract Rate by the Contract
Level (subject to adjustment of the Contract Level as provided in this
Agreement), with the Contract Rate for each of the months during the Secondary
Term specified as follows:
<TABLE>
<CAPTION>
Dates: $/KW-Month:
------ -----------
<S> <C>
Jul. to Dec. 1999 $5.10
Jan. to Dec. 2000 $5.20
Jan. to Dec. 2001 $5.30
Jan. to Sept. 2002 $5.40
</TABLE>
The Contract Rate for a particular month is subject to a performance-related
adjustment, which shall be calculated as follows:
4.9.1(a) A "Partial Nonperformance Day" occurs on any day
during which, as to any hour of such day, the Available Capacity is less
than the Contract Capacity. A "Peak Hour Partial Nonperformance Day"
occurs on any day during which, as to any Peak Hour of such Peak Day,
the Available Capacity is less than the Contract Capacity. "Available
Capacity" is the full amount of capacity (on a kilowatt-hour/hour basis)
available at the level shown in the Availability Plan. The amount of a
Partial Nonperformance Day ("PND") or Peak Hour Partial Nonperformance
Day ("PHPND") will be determined from the following equation ("Partial
Nonperformance Equation"):
PND or PHPND = CONTRACT CAPACITY - LOWEST AVAILABLE CAPACITY
---------------------------------------------
CONTRACT CAPACITY.
4.9.1(b) A "Nonperformance Day" occurs when either: (i) the
total of all Partial Nonperformance Days, as calculated in accordance
with the Partial
27
<PAGE> 34
Nonperformance Equation, equals 1; or (ii) an Overstatement Event (as
defined in Section 4.9.1(g) occurs. A "Peak Hour Nonperformance Day"
occurs when either: (i) the total of all Peak Hour Partial
Nonperformance Days, as calculated in accordance with the Partial
Nonperformance Equation, equals 1; or (ii) an Overstatement Event occurs
in a Peak Hour.
4.9.1(c) When the total of all categories of Nonperformance
Days in the current month plus the previous 11 months equals or exceeds
28, then each additional Nonperformance Day in such current month shall
be deemed to be an "Annual Excess Nonperformance Day." If less than 12
full calendar months have occurred since July 1, 1999, then the Annual
Excess Nonperformance Days are calculated using only the lesser number
of months. To reflect this lower-than-expected quality of firmness, the
Contract Rate attributable to such current month shall be reduced by an
amount equal to $0.20 per KW for each such Annual Excess Nonperformance
Day.
4.9.1(d) When the total of all Peak Hour Nonperformance Days in
any current month which is a Peak Month equals or exceeds two, then each
additional Peak Hour Nonperformance Day in such current month shall be
deemed to be a "Peak Excess Nonperformance Day." To reflect this
lower-than-expected quality of firmness, the Contract Rate attributable
to such current month shall be reduced by an amount equal to $0.40 per
KW for each such Peak Excess Nonperformance Day.
4.9.1(e) When the aggregate total of: (i) all Peak Hour
Nonperformance Days in any current month which is a Summer Peak Month;
plus (ii) all such Peak Hour Nonperformance Days during the last three
prior Summer Peak Months equals or exceeds five, then each additional
Peak Hour Nonperformance Day in such current
28
<PAGE> 35
month shall be deemed to be a "Summer Excess Nonperformance Day." If
less than four full Summer Peak Months have occurred since July 1, 1999,
then the Summer Excess Nonperformance Days are calculated using only the
lesser number of Summer Peak Months. To reflect this lower-than-expected
quality of firmness, the Contract Rate attributable to such current
month shall be further reduced by an amount equal to $0.20 per KW for
each such Summer Excess Nonperformance Day.
4.9.1(f) When the aggregate of (i) all Peak Hour Nonperformance
Days in any current month which is a Winter Peak Month, plus (ii) all
such Peak Hour Nonperformance Days during the last two prior Winter Peak
Months equals or exceeds five, then each additional Peak Hour
Nonperformance Day in that month is a "Winter Excess Nonperformance
Day." If less than three full Winter Peak Months have occurred since
July 1, 1999, then the Winter Excess Nonperformance Days are calculated
using only the lesser number of Winter Peak Months. To reflect this
lower-than-expected quality of firmness, the Contract Rate attributable
to such current month shall be further reduced by an amount equal to
$0.20 per KW for each such Winter Excess Nonperformance Day.
4.9.1(g) An "Overstatement Event" means: (i) any hour or hours
in a calendar day during which Cogenerator is requested, but is unable,
to deliver to TU Electric an amount of capacity and energy (on a
kilowatt-hour/hour basis) equal to or greater than a level which is 5 MW
less than the level shown in the Availability Plan; or (ii) any period
of a calendar day during which Cogenerator's total average delivered
capacity (on a kilowatt-hour/hour basis), averaged over the entire
period covered by a delivery request from TU Electric, does not equal or
exceed the level
29
<PAGE> 36
shown on the Availability Plan; provided that, in calculating such
average, there will be excluded from such calculation any actual
deliveries in excess of 5 MW above the level shown in the Availability
Plan. To reflect this lower-than-expected quality of firmness, TU
Electric's Capacity Payment then due to Cogenerator shall be reduced by
an amount equal to $170,000 for each Overstatement Event, except to the
extent of any event which is excused as referenced elsewhere in this
Section 4.9.1(g). If requested in writing by Cogenron, when an
Overstatement Event is declared by TU Electric, a metering accuracy test
will be performed by TU Electric at Cogenron's expense on all relevant
meters located at Cogenron. This test may be observed by both TU
Electric and Cogenron personnel, or a designee thereof, and will be used
to prove or disprove the load levels used in determining the
Overstatement Event were accurate. Cogenerator is excused from any
Overstatement Event which: (i) Cogenerator proves to TU Electric's
reasonable satisfaction: (A) to have been due to a failure that could
not have been reasonably foreseen by Cogenerator, and (B) was not done
intentionally on the part of Cogenerator, or (ii) if the failure is
because of a forced outage on TU Electric's side of the Delivery Point.
If Cogenron and TU Electric are unable to agree as to whether or not an
Overstatement Event should be excused in accordance with the preceding
sentence, then, unless both Parties agree otherwise, the issue will be
determined by final and binding arbitration, which shall occur in
Dallas, Texas and shall be conducted in accordance with the rules of the
American Arbitration Association.
4.9.1(h) Any Contract Rate reductions or Capacity Payment
reductions made under Sections 4.9.1(c) through (g) are cumulative
and, therefore, added to one
30
<PAGE> 37
another. Contract Rate reductions and Capacity Payment reductions may
occur in any month which result in reducing the Capacity Payment from TU
Electric to Cogenerator to zero for that month. Contract Rate reductions
and Capacity Payment reductions may occur in any month that result in a
negative Capacity Payment amount, and, in such event, such negative
Capacity Payment amount will represent a positive amount owed by
Cogenron to TU Electric. At TU Electric's option: (i) any additional
payments (including, without limitation, Capacity Payments and Energy
Capacity) otherwise due in succeeding months shall continue to be
reduced until all reductions have been applied; (ii) TU Electric may
offset any payments due to TU Electric by Cogenerator under this section
against any payments (including, without limitation, Capacity Payments
and Energy Payments) due by TU Electric to Cogenerator under this
Agreement; or (iii) TU Electric may invoice Cogenron for the amount due
and Cogenron shall pay such invoice within thirty days.
4.9.1(i) Determinations of Partial Nonperformance Days,
Nonperformance Days, Partial Peak Hour Nonperformance Days, Peak Hour
Nonperformance Days, Annual Excess Nonperformance Days, Summer Excess
Nonperformance Days, and Winter Excess Nonperformance Days are to be
made based upon availability of Cogenerator's power and energy for the
applicable period even if Cogenerator's ability or delivery of power and
energy to TU Electric is diminished by planned outages, forced outages,
or an event of force majeure (as force majeure is defined in Article 18
of this Agreement) except that a Partial Nonperformance Day or a Peak
Hour Partial Nonperformance Day does not occur, and a day is not a
Nonperformance Day, Peak Hour Nonperformance Day, Annual Excess
31
<PAGE> 38
Nonperformance Day, Summer Excess Nonperformance Day, or a Winter Excess
Nonperformance Day, if the Available Capacity for such day is lower than
the Contract Capacity due solely to a forced outage on TU Electric's
side of the Delivery Point.
4.9.2 Energy Payments. During the Secondary Term, the amount of
the applicable Energy Payment will depend upon the then-applicable Plant
Output as directed by TU Electric, pursuant to Section 3.1.2 of this
Agreement. The Energy Payment shall include Cogenerator's VOM charge and
a fuel charge and apply as shown on the following table:
<TABLE>
<CAPTION>
PLANT OUTPUT DIRECTION BY TU ELECTRIC EQUATION FOR ENERGY PAYMENT ($/MWH)
CONDITION
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
A TU Electric directs Plant Output to normal Energy Payment = [((8.3 x Gas Price) + VOM) x Net
Plant Output (435 MW) in 3-CT operating Energy (expressed in MWH) generated in Plant Output
mode Condition AJ; provided that this equation does not
or apply to "Ramp Hours," which are defined and
TU Electric directs Plant Output to normal governed by the subsection applicable to Plant Output
Plant Output (275 MW) with 2-CT operating Condition E below.
mode
and
hourly accumulator indicates Net Energy
exceeds 260 MW per hour
or
Cogenron declares a limitation.
- ----------------------------------------------------------------------------------------------------------------
B TU Electric requests Plant Output to maximum When in 3-CT mode, Energy Payment = [((8.3 x Gas
3-CT operating mode in excess of 435 MW; Price) + VOM) x Net Energy (expressed in MWH)
or generated in Plant Output Condition B up to 435 MW]
TU Electric requests Plant Output to maximum + [((12.0 x Gas Price) + VOM) x Net Energy
2-CT operating mode in excess of 275 MW. (expressed in MWH) generated in Plant Output
Condition B in excess of 435 MW]. When in 2-CT
mode, Energy Payment = [((8.3 x Gas Price) + VOM)
x Net Energy (expressed in MWH) generated in Plant
Output Condition B up to 275 MW] + [((12.0 x Gas
Price) + VOM) x Net Energy (expressed in MWH)
generated in Plant Output Condition B in excess of
MW].
- ----------------------------------------------------------------------------------------------------------------
</TABLE>
32
<PAGE> 39
<TABLE>
<S> <C> <C>
C TU Electric directs Plant Output to 234 MW Energy Payment = [((9.5 x Gas Price) + VOM) x Net
(250 MW in the Winter Peak Months) Energy (expressed in MWH) generated in Plant Output
(minimum 3-CT operating mode) Condition C up to 234 MW (250 MW in Peak Winter
Months)] + [an amount determined in accordance
Section 3.9 for all MWH in excess of 234 MW (250
MW in Winter Peak Months) generated in Plant Output
Condition C].
- ----------------------------------------------------------------------------------------------------------------
D TU Electric directs Plant Output to 125 MW Energy Payment = [((9.5 x Gas Price) + VOM) x Net
(140 MW in the Winter Peak Months) Energy (expressed in MWH) generated in Plant Output
(minimum 2-CT operating mode) Condition D up to 125 MW (140 MW in Peak Winter
Months)] + [an amount determined in accordance
Section 3.9 for all MW in excess of 125 MW (140 MW
in Winter Peak Months) generated in Plant Output
Condition D].
- ----------------------------------------------------------------------------------------------------------------
E Ramp Hour is the hour: Energy Payment if the Hourly Accumulator indicates
Ramp Hour 1. Immediately preceding compliance by the total MWH generated in such Ramp Hour are less
Cogenron with TU Electric's direction to Plant than 300 MWH = [((9.2 x Go Price) + VOM) x MWH
Output Condition A from Output Condition C in Ramp Hour] Energy Payment if the Hourly
or D. Accumulator indicates the total MWH generated in such
or Ramp Hour are equal to or greater than 300 MWH =
2. Immediately following compliance by [((8.3 x Gas Price) + VOM) x MWH in Ramp Hour].
Cogenron with TU Electric's direction to either
Plant Output Condition C or D.
- ----------------------------------------------------------------------------------------------------------------
</TABLE>
ARTICLE 5 - METERING, BILLING AND PAYMENT
5.1 Metering of Electrical Energy and Capacity. Electrical energy and
capacity delivered by the Cogeneration Facility to the TNP Facilities shall be
metered with equipment capable of determining energy and capacity deliveries on
a clock-hour basis. All metering and related billing costs shall be paid by
Cogenron. Meters and service switches in conjunction with such meters shall be
installed in accordance with the latest revision of the American National
Standards Institute (ANSI), Incorporated, Standard C12.1.
5.2 Monthly Metering. TU Electric or its agent shall read the meters
pertinent to said service on a monthly basis. In the event a monthly meter
reading is not made, the Parties shall mutually estimate purchases for that
month and render payment accordingly, with adjustments for
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<PAGE> 40
actual purchases being made in subsequent months; provided that, when possible,
adjustments for actual purchases shall be made in the next month's statement.
5.3 Inspection of Meters. All meters used to determine the billing
hereunder shall be sealed and the seals shall be broken only upon occasions when
the meters are to be inspected, tested or adjusted. Either Party shall have the
right to inspect and test all meters upon their installation and in accordance
with the ANSI standards regarding meter testing. Either Party may inspect or
test a meter more frequently than required hereunder, and the expense of such
inspection or test shall be borne equally by the Parties in accordance with the
prevailing provisions and fees of applicable PUC regulations on meter testing.
Such Party shall give reasonable notice to the other Party of the time when any
inspection or test shall take place, and said other Party may have
representatives present at the test or inspection. If any meter is found to be
defective or operating outside the permissible tolerances, it shall be adjusted,
calibrated, repaired or replaced by TU Electric, after Cogenron's concurrence,
at Cogenron's expense. If a meter or other measuring equipment fails to register
or, upon test, is found not to be within the accuracy standards established by
the ANSI, an adjustment, mutually agreeable to the Parties, shall be made
correcting all measurements made by such inaccurate meter or measuring equipment
for:
(l) the actual period during which inaccurate measurements
were made, if such period can be determined, or, if not;
(2) the period immediately preceding the test of the meter or
measuring equipment equal to one-half the time from the
date of the most recent test of such meter or measuring
equipment, provided that the period covered by such
correction shall not exceed six months.
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<PAGE> 41
In the event that the Parties are unable to mutually agree upon any such
adjustment, the Parties shall employ an independent consultant, selected by
mutual agreement of the Parties, to calculate an appropriate adjustment, and the
Parties agree to be bound by the results thereof.
5.4 Statement and Payment by TU Electric. TU Electric shall, within
thirty (30) days from the end of each billing period under this Agreement,
render a detailed statement with payment to Cogenron for Contract Capacity and
Net Energy received during such period. Cogenron shall have the right to
question any statement from TU Electric within one (1) year following the
rendering of such statement. TU Electric shall have the right to set-off against
any payment, fees or other charges due under this Agreement, any amounts due and
owing from Cogenron to TU Electric under this Agreement.
5.5 Interest on Overdue Payments. Interest on any overdue payment due
pursuant to this Agreement shall accrue at a rate equal to the commercial paper
rate, plus one (1) percent, charged from time to time by NationsBank in Dallas,
Texas computed on the basis of a year of 365 or 366 days, as the case may be, to
be applied from the date said payment becomes overdue until the date said
payment is received by the other Party.
ARTICLE 6 - INTERCONNECTION AND REQUIRED FACILITIES
6.1 Information Regarding Equipment. Cogenron agrees to provide to TU
Electric, upon TU Electric's request, information on the design of all equipment
associated with the Cogeneration Facility. Cogenron also agrees to request TNP
to provide to TU Electric, upon TU Electric's request, information on the design
of all equipment associated with any of the TNP Facilities.
35
<PAGE> 42
6.2 Review of Information. TU Electric shall not, by reason of its
review of Cogenron's plans and specifications referred to in this article, or by
reason of its review of any TNP plans and specifications, be responsible for
strength of materials, design, adequacy, or capability of the Cogeneration
Facility, or its associated electrical equipment, or the Intertie Equipment, or
any TNP Facilities; and such review shall not be deemed an endorsement, approval
or warranty of the Cogeneration Facility or its associated electrical equipment,
or the Intertie Equipment, or any of the TNP Facilities.
6.3 Construction and Operation of Facility. Cogenron warrants to TU
Electric that the Cogeneration Facility and associated electrical equipment have
been constructed and maintained in a good and workmanlike manner, and shall meet
or exceed industry-accepted standards. To the extent applicable, Cogenron, its
agents, servants, workmen, employees, contractors and subcontractors, shall
observe and follow the provisions of the National Electrical Safety Code in the
operation of the Cogeneration Facility.
6.4 Permits. Cogenron shall be solely responsible for obtaining any
permits or other governmental approvals necessary for the construction,
operation and maintenance of the Cogeneration Facility.
6.5 Required Facilities. TU Electric shall evaluate, design, install,
control, own, operate and maintain all Required Facilities and perform all work,
at TU Electric's expense, necessary to reliably and safely connect the Delivery
Point to the rest of the TU Electric System in order to accept and meter the
energy and capacity to be transmitted hereunder. During the term of this
Agreement, TU Electric may design, construct and install such improvements,
additions or other changes to Required Facilities as it may deem to be necessary
or desirable. TU Electric shall control, operate and maintain any such
improvements, additions or other changes.
36
<PAGE> 43
6.6 Changes to Facilities. The Parties recognize that certain
improvements, additions or other changes in or to the Point of Interconnection,
Delivery Point, or Transmission Service Providers' transmission facilities may
be required for the economical, reliable and safe transmission to TU Electric of
the energy and capacity covered hereunder. Any such improvements, additions or
changes relating to the transmission of capacity and energy covered by this
Agreement shall be made in accordance with the then-current PUC Substantive
Rules concerning open access comparable transmission service.
ARTICLE 7 - CONDITIONS OF SERVICE
7.1 Warranty By Cogenron. Cogenron warrants that the Cogeneration
Facility shall continue to produce throughout the term hereof, both the Primary
Term and the Secondary Term, sinusoidal 60 Hertz alternating current power in
accordance with normal utility standards.
7.2 System Emergency. In the event that a TU Electric System Emergency
caused wholly or partially by Cogenron or by the operation of the Cogeneration
Facility shall occur, or an emergency so caused shall occur within the ERCOT
System, Cogenron shall, upon telephonic notice by TU Electric, immediately
correct the condition which created, or is contributing to, the emergency
condition. If Cogenron cannot do so, TU Electric may immediately take whatever
action is necessary, including disconnection of the Cogeneration Facility, to
remedy the problem; it being understood that TU Electric shall have no right or
obligation hereunder to correct or otherwise repair any equipment not owned by
TU Electric. Cogenron shall bear any and all cost or expense directly related to
Cogenron's contribution to said TU Electric System Emergency through Cogenron's
operation of the Cogeneration Facility, including all costs or expenses incurred
by TU Electric or any affiliate thereof in correcting the problem.
37
<PAGE> 44
7.3 Disconnection. From time to time, TU Electric may deem it necessary
to disconnect the Transmission Service Providers' facilities from the TU
Electric System in order to make repairs, changes, tests or inspections, or in
the event of an outage of transmission facilities, a TU Electric System
Emergency, or a TU Electric System operating condition which necessitates such.
TU Electric is hereby granted the continuing right to effect such disconnection,
and Cogenron's agreement with TNP shall expressly recognize such right. TU
Electric shall provide Cogenron with such prior notice as may be reasonable or
practical under the circumstances and shall make all reasonable efforts under
the particular circumstances to restore operations as soon as possible. In no
event shall TU Electric be liable to Cogenron for such disconnection or any
costs or damages arising therefrom, so long as such disconnection by TU Electric
was effected by TU Electric in good faith.
7.4 Deficiency or Excess of Deliveries to TNP. If Cogenron fails to
deliver to TNP the amount of energy Cogenron has scheduled to deliver to TNP for
TU Electric's account, then Cogenron shall be solely responsible to TNP for any
such deficiency or excess, and Cogenron shall bear any liability resulting
therefrom.
7.5 Miscellaneous Conditions of Service. It is agreed by Cogenron and TU
Electric that:
7.5.1 TU Electric shall design, install, control and test, at
Cogenron's expense, as often as TU Electric deems necessary, the
telemetering, communications and data acquisition equipment necessary
for effective operation of the Cogeneration Facility, the TNP
Facilities, and the facilities of Houston Lightning and Power Company,
with the TU Electric System. Such equipment shall include communication
and data transmission (telemetering) facilities and control equipment
operable by TGM, and/or any alternate location designated by TU
Electric. Any leased communication facilities shall be obtained and
operated at Cogenron's expense. TU Electric shall also have the right to
design, install, control and test, as often as
38
<PAGE> 45
TU Electric deems necessary, metering equipment to monitor the fuel
supply pressure for the Cogeneration Facility.
7.5.2 All generators at the Cogeneration Facility shall remain
on line until system frequency has declined to a level below 58.5 Hertz,
and shall include equipment providing for manual or automatic trip at or
below 58.0 Hertz, with a minimum of a one-half second delay.
7.5.3 The Cogeneration Facility shall be equipped with automatic
controls for both frequency and voltage response, and Cogenron shall
give telephonic notification to PSO at any time when such automatic
controls are out of service or not functioning properly.
7.5.4 Cogenron shall staff the control room of the Cogeneration
Facility with a qualified operator(s) during all hours when the
Cogeneration Facility is in operation.
7.5.5 TU Electric shall promptly notify Cogenron's operator(s)
of any outage or malfunction of equipment and facilities on the TU
Electric System that would prohibit or limit TU Electric's receipt of
power and energy generated by the Cogeneration Facility or any other
condition affecting operation of the Cogeneration Facility. Cogenron
shall report performance of the Cogeneration Facility to TU Electric
utilizing the standard Generator Availability Data System methodology of
the National Electric Reliability Council and in a format and medium
acceptable to TU Electric. In addition, Cogenron shall supply sufficient
data for the calculation of the Peak Hour Rolling Average Capacity
Factor Performance Level.
7.5.6 Cogenron shall obtain prior telephonic approval of PSO for
any closing of main circuit breakers of the Cogeneration Facility,
whether for testing or for operations, and of any outage of, or
limitation on, generation by Cogenron's facility.
39
<PAGE> 46
7.5.7 Cogenron shall keep maintenance records of the
generator(s) and control and protective equipment at the Cogeneration
Facility, which records shall be available to TU Electric for inspection
at all reasonable times.
7.5.8 Cogenron shall furnish TU Electric with its long-term
preventive maintenance program for each major item of equipment of the
Cogeneration Facility, including a schedule of planned outages for
inspection, repair, maintenance and over-haul. Such maintenance
information shall be furnished as soon as practicable following
installation of the Cogeneration Facility. Maintenance programs shall be
based on manufacturer's recommendations and may be altered from time to
time by reason of later manufacturer's releases pertaining to major
items of equipment of the Cogeneration Facility together with the
experience of Cogenron in operating same. Cogenron shall promptly advise
TU Electric of any such changes. The specific times for planned outages
of the Cogeneration Facility shall be scheduled annually in advance by
agreement of TU Electric and Cogenron so as to coordinate planned
outages of the Cogeneration Facility with planned outages of TU
Electric's generating facilities, of generating facilities of others
interconnected with the TU Electric System, and of TU Electric's
transmission facilities necessary to receive power and energy from the
Cogeneration Facility.
7.5.9 Cogenron shall report to PSO, on a timely basis, those
items and/or conditions necessary for TU Electric's internal planning
and compliance with TU Electric's guidelines in effect from time to
time. The information supplied shall include, without limitation, the
following: (1) status (on or off line) within 15 minutes; (2)
Availability Plan for the next business day and for any other day prior
to the next business day which is not a business day, including capacity
available from the Plant; (3) generating equipment overhaul or scheduled
40
<PAGE> 47
outage plans for the year (updated weekly); (4) any scheduled or planned
transmission or switchyard clearances or maintenance plans for the next
twelve (12) months (updated weekly); (5) time and cause of outage of
Cogenron's generator(s) or circuit breaker(s) included in Cogenron's
Cogeneration Facility; (6) monthly generation estimates by August 1 for
the next calendar year, (7) prompt updates of the monthly generation
estimates when any changes are anticipated; and (8) at least thirty
(30) days prior to each calendar quarter, generation estimates,
calculated on a month-by-month basis, for the next twelve (12) month
period.
7.5.10 Spinning Reserve. During the Primary Term, at any time
when the temperature at the Cogeneration Facility is below 85 degrees F
and up to a maximum of two hundred (200) hours in each calendar year
when said temperature is above 85 degrees F, Cogenron shall, if
requested by TU Electric, provide at least six percent (6%) additional
capacity of the then released capacity for a minimum of six (6)
consecutive hours. The only exception to the foregoing will be those
hours in which the steam demand on the Cogeneration Facility is 300,000
lbs/hr or less, in which case Cogenron will provide 15 MW of additional
capacity. The Cogeneration Facility will be operated in such a manner as
to allow such response to be at a rate of seventy (70) MW in twelve and
one-half (12 1/2) seconds. This Section 7.5.10 shall have no
application during the Secondary Term hereof.
7.6 Duty to Use Good Faith & Gas Supply. All contracts for the supply of
fuel to the Cogeneration Facility shall be negotiated and consummated by
Cogenron in good faith in a manner designed to result in an economic, reliable
and consistent supply of fuel in such quantities as are necessary for Cogenron
to perform its obligations under this Agreement. Both Parties shall continue to
explore methods for providing a natural gas supply for the Plant; provided that,
Cogenron's
41
<PAGE> 48
obligations to maintain such supply of gas throughout the Primary Term and
Secondary Term, are not in any event, diminished or affected. Cogenron's total
compensation for fuel, including all transportation, balance premium and other
costs of obtaining fuel supply are included in the Energy Payments.
By April 1, 1998, Cogenron and TU Electric will jointly prepare a
solicitation to acceptable, potential natural gas suppliers detailing the
following information: (a) the delivery point of the gas; (b) the quality of the
gas required; (c) estimated quantities of gas (on an annual and monthly basis)
to be supplied; and (d) the term of such gas deliveries. The solicitation will:
(i) request that bidders offer a gas price per MMBtu based on an acceptable
published natural gas index and (ii) require that bids must be received no later
than May 1, 1998 to be considered. TU Electric will assist Cogenron in the
evaluation of the bids and subsequent negotiation of a gas supply contract. A
gas supply contract, which is mutually acceptable to Cogenron and TU Electric,
will be executed by Cogenron, as purchaser, and the third party, as seller, on
or before June 30, 1998.
If a gas supply contract, which is mutually agreeable to Cogenron and TU
Electric, has not been executed by June 30, 1998, TU Electric, at its sole
election, may elect to supply gas for the Cogeneration Facility during the
Secondary Term upon delivery of written notice to Cogenron by June 30, 1998;
provided that, after receipt of such notice, TU Electric and Cogenron hereby
agree to negotiate in good faith a written amendment to this Agreement setting
out mutually-agreeable terms relating to the supply of gas by TU Electric,
including, without limitation, a provision setting TU Electric's gas supply
obligation at levels for the various Plant Output Conditions that reflect the
heat rates assumed in the equations for Energy Payments contained in the table
set forth in Section 4.9.2.
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7.7 Duty to Inform. Cogenron shall keep TU Electric informed of all
matters significant with respect to the construction and operation of the
Cogeneration Facility and the supply of fuel thereto.
ARTICLE 8 - OWNERSHIP, INSTALLATION AND MAINTENANCE OF EQUIPMENT 8.1 Cost
of Installation and Maintenance. TU Electric shall bear no costs associated with
the maintenance, installation or operation of the Cogeneration Facility or the
Point of Interconnection.
8.2 Ownership. Cogenron shall own, operate, maintain and repair the
Cogeneration Facility at its sole cost and expense, and maintain such facility
in a safe and proper operating condition consistent with all applicable
statutes, regulations, codes, and the duties and obligations stated herein. In
addition, Cogenron shall operate such Cogeneration Facility in accordance with
all of the requirements, guidelines and specifications of TU Electric, as
amended from time to time.
8.3 Cogenron's Liability. Cogenron shall be solely responsible for the
installation, maintenance, and operation of any equipment it deems necessary to
protect the Cogeneration Facility from faults or other conditions on the TU
Electric System, or the TNP Facilities. In addition, Cogenron shall be solely
responsible for, and shall indemnify TU Electric against any liability for, all
present or future federal, state, municipal or other taxes applicable by reason
of the sale of energy and capacity hereunder, or related to the Contract
Capacity, or the installation of the Cogeneration Facility, or otherwise.
8.4 Costs Billed to Cogenron. Any costs to be billed by TU Electric to
Cogenron pursuant to this Agreement will include all out-of-pocket costs of TU
Electric, as well as all internal TU Electric costs, including labor, materials
and equipment, together with fully distributed loading of associated overhead
costs in accordance with TU Electric's standard costing practices. Unless
43
<PAGE> 50
otherwise provided by this Agreement, all payments from Cogenron to TU Electric
pursuant to this Agreement shall be payable within thirty (30) days of
Cogenron's receipt of an invoice from TU Electric.
ARTICLE 9 - INSPECTION AND ACCESS RIGHTS
9.1 Access Rights. Cogenron shall cause TNP to allow TU Electric,
throughout the term of this Agreement (and a reasonable time thereafter)
rights-of-way and easements adequate for TU Electric to install, operate,
maintain, repair, replace and remove any facilities or associated electrical
equipment used in connection with any of the operations covered hereunder and
connected to, or affecting in any way, the TU Electric System, including
adequate and continuing access rights. Cogenron shall execute such other
grants, deeds or documents as TU Electric may require to enable it to record
such rights-of-way and easements.
9.2 TU Electric Inspection. Cogenron shall permit and shall cause any
third parties over which it has control to permit employees and inspectors of
TU Electric to examine and conduct such operating tests and inspections as are
reasonably deemed necessary by TU Electric to ascertain that the Intertie
Equipment is functioning properly. Cogenron shall reimburse TU Electric for all
costs associated with such inspection or tests.
ARTICLE 10 - TERMINATION
10.1 Right to Terminate. In addition to the other causes for
termination provided herein, TU Electric shall have the right, except during
occurrences of force majeure (as defined in Article 18 of this Agreement) to
terminate this Agreement, upon written notice, without any liability or
44
<PAGE> 51
responsibility hereunder, and without prejudice to any other power, right or
remedy which TU Electric may have hereunder, if any or all of the following
enumerated events occur:
10.1.1 In the event of Cogenron's bankruptcy or insolvency, or in
the event of the initiation of any proceeding, voluntary or involuntary,
against Cogenron under the bankruptcy or insolvency laws, or in the event
of Cogenron's inability to meet its debts in the ordinary course of
business; provided, however, that there shall be no termination of this
Agreement if, within ten (10) days from the receipt of written notice from
TU Electric to terminate, Cogenron as debtor in possession, or Cogenron's
trustee, receiver, assignee or custodian, whichever is obligee under this
Agreement, in writing affirms this Agreement and demonstrates, to TU
Electric's satisfaction, the ability to fulfill its or their obligations
under this Agreement.
10.1.2 In the event any disconnection effected pursuant to Article
7.2 or otherwise hereunder continues for sixty (60) days due to Cogenron's
failure to correct or remedy the cause thereof or its portion of the cause
thereof, provided, however, that if any such cause (other than a failure
to make any required payment hereunder) cannot by the exercise of due
diligence be cured within such sixty (60) day period, TU Electric shall
not have the right to terminate this Agreement if Cogenron within such
sixty (60) day period has taken all steps necessary to begin the cure of
such cause so as to effect said cure as soon after the expiration of such
sixty (60) day period as may be feasible.
However, TU Electric shall have the right to terminate this
Agreement for any such cause of disconnection that continues for six (6)
months from the disconnection date, regardless of Cogenron's attempts to
correct such. No termination shall occur, however, in the event both
Parties agree that satisfactory efforts are being made to cure such cause.
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<PAGE> 52
10.1.3 [Deleted.]
10.1.4 Construction of the Cogeneration Facility is abandoned or
operation of the Cogeneration Facility is abandoned after construction
thereof
10.1.5 If either of the following events occur: (1) during the
Primary Term, if Cogenron fails to deliver energy at an Peak Month Rolling
Average Capacity Factor Performance Level equal to, as a minimum, fifty
percent; or (2) during the Primary Term, if Cogenron fails to deliver
energy at a Peak Hour Rolling Average Capacity Factor Performance Level
equal to, as a minimum, fifty percent.
10.1.6 Cogenron fails to deliver energy at a Capacity Factor
Performance Level equal, as a minimum, to fifty percent (50%) during any
twelve (12) month period during the Primary Term.
10.1.7 TNP or any other Transmission Service Providers becomes
unwilling, unable or fails for any reason, for a period of 180 consecutive
days, to transmit the energy and capacity covered hereunder from the
Cogeneration Facility to the TU Electric System, as required herein.
10.1.8 Cogenron ceases to operate the Cogeneration Facility for a
period of ninety (90) consecutive days, or Cogenron is unable, unwilling,
or fails for any reason to generate and have available for transmission
the capacity and energy required hereunder or deliver Comparable Energy
and Capacity as provided in Article 11.3 below.
10.2 Bankruptcy or Insolvency of TU Electric. In the event of TU
Electric's bankruptcy or insolvency, or in the event of the initiation of any
proceedings, voluntary or involuntary, against TU Electric under the bankruptcy
or insolvency laws, or in the event of TU Electric's inability to meet its debts
in the ordinary course of business, Cogenron, upon providing written notice, may
terminate
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<PAGE> 53
this Agreement; provided, however, there shall be no right to terminate
hereunder if, within ten (10) days from the receipt of written notice from
Cogenron to terminate, TU Electric, as debtor in possession, or TU Electric's
trustee, receiver or custodian, whichever is obligee under this Agreement, in
writing affirms this Agreement and demonstrates to Cogenron's reasonable
satisfaction the ability to fulfill its or their obligations under this
Agreement. In the event of such termination, however, TU Electric will, at
Cogenron's request, use its best efforts to transmit electricity at the then
PUC-approved rules and rates from the Point of Delivery hereunder to any other
electric utility that Cogenron may designate from among the utilities
interconnected with the TU Electric System; provided that such transmission does
not jeopardize the reliability of the TU Electric System and can be done
consistent with TU Electric's service obligations under Texas and federal law.
10.3 Disposition of Plant and Equipment. Cogenron shall be solely
responsible for any costs associated with the removal, relocation or other
disposition of the Cogeneration Facility and the Intertie Equipment upon
termination of this Agreement.
ARTICLE 11 - LIMITATION OF LIABILITY; PAYMENT ON TERMINATION;
SUPPLY OF COMPARABLE ENERGY AND CAPACITY; RECOUPMENT
OF EARLY CAPACITY PAYMENT; INDEMNITY
11.1 Limitation of Liability. Notwithstanding any other provision of this
Agreement to the contrary, neither Party shall be liable to the other hereunder
for loss of profits (except for those which would have been earned under this
Agreement), cost of capital, consequential damages, attorneys fees, damages
arising out of business interruption or costs of business relocation. Moreover,
Cogenron agrees to indemnify TU Electric against, and hold TU Electric harmless
from any claims, demands, suits and liability of any nature raised or made by
Union Carbide Corporation, or by any
47
<PAGE> 54
former or current parent, subsidiary or affiliate of Cogenron Inc., or by TNP in
connection with this Agreement, or any operation thereunder, of the Cogeneration
Facility.
11.2 Payment on Termination. In the event that, during the Primary Term,
this Agreement is ever terminated pursuant to the provisions of Articles 10.1
(except for certain instances of termination under Article 10.1.7, as referenced
below in this Article 11.2), 12.2 or 15.3 of this Agreement, Cogenron shall pay
to TU Electric an amount equal to ten percent (10%) of the remaining Capacity
Payments and Energy Payments which would have otherwise been payable to Cogenron
for the remaining Primary Term under this Agreement, had such payments been made
with a 6.5% per annum progressive payment and an assumed 65% Annual Capacity
Factor Performance Level, as calculated below. Cogenron shall pay to TU Electric
the amount shown below for the year in which the termination occurs and shall
also, in addition to the numbers shown below, include interest at the commercial
paper rate charged from time to time by NationsBank in Dallas, plus one percent,
such interest to commence accrual as of the date of termination of this
Agreement. Such payment amount upon termination of this Agreement shall be as
follows:
<TABLE>
<CAPTION>
Termination Payment Amount
during calendar year: (not including interest):
--------------------- -------------------------
<S> <C>
1987 $ 82,984,000
1988 81,061,000
1989 76,110,000
1990 74,103,000
1991 71,916,000
1992 69,055,000
1993 65,167,000
1994 60,149,000
1995 53,744,000
1996 45,313,000
1997 34,827,000
1998 22,745,000
1999 8,350,000
</TABLE>
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<PAGE> 55
The applicable sum of money shall be payable to TU Electric, in full,
thirty days following the termination of this Agreement; provided, however,
should a termination of this Agreement occur pursuant to Article 10.1.7, the
payment provided in this Article 11.2 shall not apply unless the unwillingness,
inability or failure of TNP or any other Transmission Service Provider to
transmit the energy and capacity covered hereunder is due or attributable to
some act or omission on the part of Cogenron.
11.3 Supply of Comparable Energy and Capacity. In the event Cogenron
ceases operation of the Cogeneration Facility, Cogenron may deliver in
accordance with the terms hereof to TU Electric Comparable Energy and Capacity
produced at another facility within ERCOT, and TU Electric shall accept and pay
for, in accordance with the terms of this Agreement, such energy and capacity as
fulfillment of Cogenron's duties and obligations under this Agreement, provided
that such energy and capacity complies in all respects with the definition of
Comparable Energy and Capacity as contained herein. If Cogenron delivers such
Comparable Energy and Capacity, payment for same shall be the sole
responsibility of Cogenron and TU Electric shall not be liable under any
circumstances for any payments to third parties including, without limitation,
all transmission service charges and fees of any nature. If Cogenron ever ceases
to deliver, in accordance with all the terms hereof, such Comparable Energy and
Capacity (other than any cessation due to a rejection by TU Electric of such
Comparable Energy and Capacity due to cost, as provided below in this Article
11.3), then this Agreement shall terminate as of the date of such cessation and
the applicable amount under Article 11.2 shall become fully due and payable.
TU Electric shall have the continuing right to reject and refuse to pay
Cogenron for any Comparable Energy and Capacity tendered by Cogenron at any time
under this Article 11.3, if TU Electric is able to obtain such energy and
capacity at a lower cost than would be payable to Cogenron
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<PAGE> 56
under this Agreement. In the event of such rejection by TU Electric, Cogenron
shall have no further obligation to deliver Comparable Energy and Capacity
hereunder for the remainder of the then current calendar year. Commencing with
January I of the following year, Cogenron's obligations to deliver energy and
capacity, or Comparable Energy and Capacity, shall commence again in accordance
with all of the terms and provisions hereof, subject to TU Electric's subsequent
exercise of its right of rejection.
11.4 Recoupment of Early Capacity Payment. In the event of the termination
of the Agreement for any reason prior to twelve years following the Commercial
Operating Date, Cogenron shall pay to TU Electric the amounts shown below for
the year in which such termination occurs. (For example, if termination of this
Agreement occurs in the year 1987, Cogenron would owe TU Electric $7,475,000 to
compensate for early capacity payments, plus interest, made by TU Electric to
Cogenron hereunder.)
<TABLE>
<CAPTION>
Year Amount Due,
---- -----------
<S> <C>
1987 $ 7,475,000
1988 29,575,000
1989 33,566,000
1990 42,280,000
1991 49,461,000
1992 54,699,000
1993 57,519,000
1994 57,316,000
1995 53,441,000
1996 45,141,000
1997 31,549,000
1998 11,619,000
1999 -0-
</TABLE>
11.5 Termination Other Than at End of Year. The amounts shown in Article
11.4 are payable by Cogenron to TU Electric for termination of the Agreement at
the end of the corresponding year. If such termination occurs other than at the
end of a year, then the amount to be paid by
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Cogenron to TU Electric to enable TU Electric to recoup early capacity payments
shall be the sum of the amount payable had termination occurred at the end of
the year prior to the date of termination, plus interest thereon at the rate of
11.75% per annum from the end of such prior year until the date of termination,
plus such portion of the appropriate amount shown below as is proportional to
the day of the year on which the Agreement is terminated.
<TABLE>
<CAPTION>
Year of Termination Amount to be Apportioned
------------------- ------------------------
<S> <C>
1988 $21,222,000
1989 515,000
1990 4,771,000
1991 2,213,000
1992 (574,000)
1993 (3,608,000)
1994 (6,960,000)
1995 (10,611,000)
1996 (14,580,000)
1997 (18,895,000)
1998 (23,635,000)
1999 (12,281,000)
</TABLE>
11.6 Indemnity. In addition to other indemnities provided herein Cogenron
agrees to defend, protect, indemnify, and save harmless TU Electric, parent or
affiliate corporations, their agents, servants, officers, directors, and
employees, from and against all claims, expenses, demands, judgments, and causes
of action of every kind and character for personal injury or death or damage to
property of Cogenron's agents, servants, and employees, as well as the agents,
servants, and employees of Cogenron's contractors, arising out of or incident
to the construction, operation or maintenance of the Cogeneration Facility.
Cogenron shall defend, protect, indemnify, and save harmless TU Electric,
and its parents or affiliate corporations, and their officers, directors,
agents, servants, and employees from and against any and all claims, expenses,
demands, judgments, and causes of action of every kind and character
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whatsoever arising in favor of any person or entity (other than the agents,
servants, and employees of Cogenron or of Cogenron's contractor, as provided in
the paragraph immediately above), including but not limited to claims, demands,
judgments, causes of action on account of personal injuries or death, or damage
to property arising out of or incident to the construction, operation or
maintenance of the Cogeneration Facility. It is the clear and unequivocal intent
of the Parties hereto that Cogenron's obligation to defend, protect, and save
harmless TU Electric shall be full and complete for any work performed, with the
only exception being that, as to claims arising in favor of persons or entities
other than for injury, death, or damage to the agents, servants, and employees
of Cogenron or Cogenron's subcontractor, TU Electric shall not be entitled to
indemnification for claims, demands, expenses, judgments, and causes of action
resulting from TU Electric's sole negligence.
ARTICLE 12 - NO OPERATION IN INTERSTATE COMMERCE
12.1 Cogenerator Warranties. Cogenerator represents and warrants:
12.1.1 that Cogenerator does not, and will not, directly or through
connections with other entities transmit sell, or deliver electric energy
generated at the Plant in interstate commerce, other than electric energy
that is put into interstate commerce after it is delivered to TU Electric;
and
12.1.2 that Cogenerator has opened, and will keep open, all
electrical connections controlled by it that are necessary to prevent
transmission of electric energy generated at the Plant in interstate
commerce before it is delivered to TU Electric.
12.2 Right to Suspend and Terminate. If Cogenerator transmits, sells,
delivers, purchases, or receives electric energy delivered to TU Electric in
interstate commerce or maintains any
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interconnection for those activities, then TU Electric may, besides any other
remedies it may have, including the remedy specified in Section 12.3 below,
exercise either or both of these remedies:
12.2.1 immediately suspend receipt of electric power and energy
from, and delivery of power and energy to, Cogenerator; or
12.2.2 immediately terminate this Agreement by sending written
notice of termination to Cogenerator.
12.3 Specific Performance. It is impossible or very difficult to
measure in money the damages that would accrue due to any breach of the
representations and warranties made in this Article 12, or any failure in
the performance of any of the obligations contained in this Article 12
and, for that reason, among others, the Parties agree that TU Electric is
entitled to specific performance of this Article 12, besides any other
remedies that may exist and, for that reason, among others, the Parties
agree that TU Electric is entitled to specific performance of this Article
12, besides any other remedies that may exist. Cogenerator waives any
claim or defense that an adequate remedy at law exists, if TU Electric
institutes any proceedings to enforce any provision of this Article 12.
12.4 Exceptions. Nothing in this Article 12 precludes the use of
connections for the transmission of electric energy in interstate commerce
(i) under bonafide emergencies under Section 202(d) of the Federal Power
Act or (ii) if such transmission in interstate commerce occurs because of
the orders of the Federal Energy Regulatory Commission, applicable to TU
Electric, under Sections 210, 211, and 212 of the Federal Act requiring
the establishment, maintenance, modification, or use of any connections
that are involved.
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ARTICLE 13 - NOTICE
13.1 Notices. Unless otherwise stated herein, all notices, demands or
requests required or permitted to be given by either Party to the other under
this Agreement, or any instrument or document required or permitted to be
tendered or delivered by either Party shall be made: (1) by depositing the same
in any United States Post Office, postage prepaid, for transmission by certified
or registered mail (except that payments may be forwarded by regular mail)
addressed to the other Party, or (2) by personally delivering to the other
Party, such transmittal at the following addresses:
If to TU Electric:
with respect to scheduling and dispatching:
Generation Coordinator
Power Supply Operations Group
TU Electric Company
1601 Bryan Street
Dallas, Texas 75201-3411
(214) 812-6240.
with respect to all other matters:
Henry A. Bunting
Manager, Power Resource Acquisition
TU Electric Company
1601 Bryan Street
Energy Plaza, 12th Floor
Dallas, Texas 75201-3411.
If to Cogenron:
with respect to Cogeneration Facility operations:
Shift Supervisor
3221 Fifth Avenue South
Texas City, Texas 77590
(409) 945-7324.
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with respect to all other matters:
President
700 Louisiana, Suite 2360
Houston, Texas 77002
(713) 230-2102.
13.2 Change of Address. Changes in the aforesaid addresses shall be made
by the notice procedure described in Section 13.1 of this Article 13.
ARTICLE 14 - LIABILITY; DEDICATION; SEVERAL OBLIGATIONS
14.1 Liability. TU Electric does not, by review and acceptance of the
plans and specifications for the construction of the Cogeneration Facility,
assume any responsibility or liability for damage or physical injury to: (1) TU
Electric real or personal property or electrical equipment, (2) the real or
personal property of third persons or corporations not a party to this
Agreement, including, but not limited to, Union Carbide Corporation and TNP, (3)
the real or personal property and equipment (including the Cogeneration
Facility) of Cogenron, and (4) any persons who may come in contact with or upon
the Cogeneration Facility and associated equipment; and (5) any other persons or
property, real or personal.
14.2 Dedication. No undertaking by either Party to the other under any
provision of this Agreement shall constitute the dedication of that Party's
electrical system, equipment, or facilities, or any portion of any of the
foregoing, to the other Party or to the public, or affect the status of TU
Electric as an independent corporate entity and a public utility, or Cogenron as
an independent corporate entity.
14.3 Several Obligations. Except where specifically stated otherwise in
this Agreement, each of the duties, obligations and liabilities of the Parties
is to be a several obligation, duty or liability
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and not joint or collective. Nothing contained in this Agreement shall ever be
construed to create an association, trust, partnership or joint venture, or
impose a trust or partnership duty, obligation or liability, on or with regard
to either Party.
ARTICLE 15 - REPRESENTATIONS AND WARRANTIES OF THE RESPECTIVE PARTIES
15.1 Cogenron's Representations and Warranties. In addition to the other
representations, obligations, and warranties of Cogenron provided herein,
Cogenron hereby represents and warrants unconditionally to TU Electric that:
15.1.1 Cogenron is a corporation duly organized, validly existing
and in good standing under the laws of the State of Delaware, and has been
duly authorized to do business in the State of Texas.
15.1.2 Cogenron has full corporate power and lawful authority to
accomplish, execute and fulfill all of its obligations and duties
hereunder.
15.1.3 The making and performance by Cogenron of this Agreement have
been duly authorized by all necessary corporate action and will not: (i)
violate any provision of any law, rule, regulation, order, writ, judgment
decree, determination or award presently in effect having applicability to
Cogenron; (ii) violate any provision of the Articles of Incorporation or
Bylaws of Cogenron, or (iii) result in a breach of or constitute a default
under any mortgage, indenture or bank loan or credit agreement or any
other material agreement or instrument to which Cogenron is a party or by
which it or its property is presently bound or affected.
15.1.4 All authorizations, permits, consents, approvals, licenses or
exemptions of, and filings or registrations with, any court or
governmental agency or other authority,
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<PAGE> 63
domestic or foreign, necessary to permit Cogenron to execute and deliver,
and to perform its obligations under this Agreement, have been obtained or
made at Cogenron's sole expense, and Cogenron is not, and will not be, in
violation or default in any respect of or under any law, rule, regulation,
order, writ, judgment, decree, determination or award, and is not, and
will not be, in violation of or default under any mortgage, indenture,
agreement or instrument.
15.1.5 Cogenron possesses the necessary expertise, technology,
manpower, equipment, financial resources and experience to fulfill all of
Cogenron's obligations hereunder, including, but not limited to,
Cogenron's licensing, procurement, transportation, sale, quantity,
quality, and marketing obligations hereunder.
15.1.6 The Cogeneration Facility is, and will continue to be,
throughout the Primary and Secondary Term, a Qualifying Facility, as that
term is used and defined in 18 CFR (Code of Federal Regulations) 292, and
has been since the date of this Agreement in 1985, and, upon request,
Cogenron will provide certification by the FERC of such qualifying status
pursuant to 18 CFR 292.207(b).
15.1.7 Cogenron will comply in a timely manner with all of the
terms, provisions and conditions of this Agreement throughout the term
hereof.
15.1.8 Cogenron shall maintain throughout the term hereof a reliable
fuel supply for the Cogeneration Facility sufficient for such facility to
meet the energy and capacity requirements provided herein.
15.2 TU Electric's Representations and Warranties. TU Electric
hereby represents and warrants unconditionally to Cogenron that:
15.2.1 TU Electric is a corporation duly organized, validly existing
and in good standing under the laws of the State of Texas.
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<PAGE> 64
15.2.2 The making and performance by TU Electric of this Agreement
have been duly authorized by all necessary corporate action and will not:
(i) violate any provision of any law, rule, regulation,
order, writ, judgment, decree, determination or award
presently in effect having applicability to TU Electric;
(ii) violate any provision of the Articles of
Incorporation or Bylaws of TU Electric; or
(iii) result in a breach of or constitute a default
under any indenture or bank loan or credit agreement or any
other material agreement or instrument to which TU Electric is
a party or by which it or its property is presently bound or
affected.
15.2.3 All authorizations, permits, consents, approvals,
licenses or exemptions of, and filings or registrations with, any
court or governmental agency or other authority, domestic or
foreign, necessary to permit TU Electric to execute and deliver, and
to perform its obligations under, this Agreement have been obtained
or made, and TU Electric is not in violation or default in any
material respect of or under any law, rule, regulation, order, writ,
judgment, decree, determination or award and is not in violation of
or default under any mortgage, indenture, agreement or instrument.
15.3 Misrepresentation; Breach of Warranty; Fulfillment of Obligations. In
the event either Party hereto materially breaches any warranty provided herein,
or fails to fulfill any material obligation provided herein, or if any material
representation given herein becomes, subsequent to the date hereof, inaccurate,
or is discovered to have not been accurate when made, then the Party to whom
such representation or warranty was made, or to whom such obligation was due,
may, in addition to any other remedies which may be available at law or in
equity, terminate this Agreement upon thirty (30) days' written notice to the
other Party (such thirty (30) days commencing with the
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<PAGE> 65
date of the other Party's receipt of such notice), if, by the end of said thirty
(30) day period, the other Party has not cured such breach, misrepresentation or
default. Said thirty (30) day notice period shall not be applicable to
termination under Article 10.1 or Article 12.2.
ARTICLE 16 - INSURANCE
16.1 Proof of Coverages. Cogenron shall require that its insurance
carriers provide to TU Electric proof of insurance as required by Article 16.5
in the form of two (2) copies of an insurance certificate form acceptable to TU
Electric. All policies shall be written with insurers acceptable to TU Electric
and the certificates received not less than ten (10) days after execution of the
Agreement. Such certificates shall provide that there will be sixty (60) days'
written notice given to TU Electric of any change in or cancellation of any
policy upon which a certificate is required of Cogenron by this Article hereof.
All coverages required of Cogenron shall be in full force and effect during
Cogenror's performance of this Agreement.
16.2 Policies. All policies shall be written on an occurrence basis,
unless an occurrence basis policy becomes unavailable and shall include TU
Electric, its directors, officers, agents, servants, employees and/or
independent contractors directly responsible to TU Electric as additional
insureds. All policies shall contain an endorsement (if such terminology is not
in the printed form) that Cogenron's policy shall be primary in all instances
regardless of like coverages, if any, carried by TU Electric.
16.3 Certificates. All certificates required in this Article 16 shall be
furnished to TU Electric and shall be subject to the approval and acceptance of
TU Electric, which shall not be unreasonably withheld.
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<PAGE> 66
16.4 Limitation of Liability. Cogenron's liability under this Agreement is
not limited to the amount of insurance coverage required herein.
16.5 Coverage and Limits of Liability. Cogenron at its sole expense shall
maintain the following types of coverage and limits of liability:
<TABLE>
<CAPTION>
Limits of Liability
Type of Coverage of Insurance Policy
---------------- -------------------
<S> <C>
(1) Workers' Compensation Insurance Statutory
(2) Employees Liability Insurance 1,000,000 per occurrence
(3) Comprehensive General Public
Liability Insurance $20,000,000 per occurrence
Including: Coverage for damage
caused by blasting, collapse,
underground damage or explosion;
Independent Contractors;
Products, Completed Operations;
Personal Injury; Contractual
Public Liability covering
liability assumed in the
Agreement; Broad Form Property
Damage; and Excess Employees
Liability.
(4) Comprehensive Automobile
Liability $20,000,000 per occurrence
including: Coverage for all owned,
hired or non-owned licensed
automotive equipment.
</TABLE>
For Items 3 and 4 above the first $250,000 shall be external coverage, the next
$750,000 may be self-insured, and the remainder up to $20,000,000 shall be
external coverage.
16.6 Release and Waiver. Cogenron agrees to release, and will require
its insurers (by policy endorsement) to waive their rights of subrogation
against, TU Electric, its directors, officers,
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<PAGE> 67
agents, servants, employees and/or independent contractors directly responsible
to TU Electric for loss under the policies of insurance described herein,
damages to Cogenron's properties and/or any other loss sustained by Cogenron,
whether insured or not.
ARTICLE 17 - TRANSMISSION SERVICE AGREEMENTS
17.1 Negotiation. Except for Comparable Energy and Capacity, TU Electric
will administer any transmission service agreements required to deliver energy
and capacity to the Point of Delivery. Cogenron shall have the right to approve
all transmission service agreements that apply to transmission service during
the Primary Term prior to execution by TU Electric, which approval will not be
unreasonably withheld.
17.2 Transmission Service Charge. Except for Comparable Energy and
Capacity, it is agreed that:
17.2.1 Cogenron will reimburse TU Electric for various
percentages of all charges, fees and expenses for transmission service
and line losses (including, without limitation, Access, Impact and loss
components, as now and subsequently defined by the PUC) paid, in money
or in kind, by TU Electric and Cogenron agrees to compensate TU Electric
for any payments due here from TU Electric arising from transmission
service charges, fees and expenses and line losses attributable to
energy and capacity delivered at the Point of Delivery, such
reimbursement by Cogenron to TU Electric to be in the following
percentages for the time periods indicated:
17.2.1 (a) Prior to midnight on December 31, 1996, such
reimbursement by Cogenron will be 100%.
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17.2.l(b) From midnight on December 31, 1996, to midnight on
June 30, 1999, such reimbursement shall be 60% for all Access and Impact
charges and 100% for all loss components experienced by TU Electric.
17.2.l(c) Effective as of midnight on June 30, 1999, there shall
be no further reimbursement.
17.2.2 During the Primary Term, Cogenron will pay any and all
termination and similar charges due under the terms of all transmission
service agreements required pursuant to Section 17.1 to deliver the
cogenerated energy and capacity to the Point of Delivery. Cogenron also
agrees to indemnify TU Electric against any and all liabilities, costs
and expenses, including attorney's fees, which TU Electric may have for
termination and similar charges arising under any such agreements.
17.2.3 Cogenron will have no liability under Sections 17.2.1 or
17.2.2 for termination charges or for charges for transmission and line
losses paid by TU Electric under any such transmission service
agreements which accrue subsequent to midnight, on June 30, 1999, or
subsequent to any purchase or lease of the Cogeneration Facility by TU
Electric pursuant to Article 21 hereof.
17.2.4 TU Electric shall have the right to deduct, from its
payments to Cogenron, in the percentages and for the time periods
indicated in Sections 17.2.1(a) through 17.2.1(c), termination
charges and charges for all transmission service charges and line losses
paid by TU Electric, whether in money or in kind, in respect to or in
connection with any energy and capacity delivered to TU Electric under
this Agreement.
17.3 Transmission of Comparable Energy and Capacity. If Cogenron
delivers Comparable Energy and Capacity in accordance with the
provisions of this Agreement, Cogenron will be
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responsible for: (i) the negotiation of all transmission service agreements
necessary to deliver the Comparable Energy and Capacity to the Delivery Point,
and (ii) all such transmission service charges and fees, including without
limitation, all Access and Impact charges and all loss components, attributable
to the delivery of such Comparable Energy and Capacity to the Delivery Point.
17.4 Execution of Transmission Service Agreements. TU Electric shall use
reasonable efforts to execute and maintain transmission service agreements with
Houston Lighting & Power Company ("HL&P"), with TNP, and with all other
Transmission Service Providers necessary for the transmission of energy and
capacity generated by the Cogeneration Facility and delivered to TU Electric.
ARTICLE 18 - FORCE MAJEURE
18.1 Definition. The term force majeure, as used herein, means acts of
God, sudden actions of the elements, such as floods, hurricanes or tornadoes,
and actions by federal, state, municipal or any other government or agency,
sabotage, war or riots.
18.1.1 The term force majeure does not include any full or
partial curtailment in the electric output of the Facility which is
caused by or arises from the act or acts of any third party including,
without limitation, any vendor or supplier of Cogenerator, unless such
act or acts is itself excused by reason of force majeure.
18.1.2 The term force majeure does not include any full or
partial curtailment in the electric output of the Facility that is
caused by or arises from a mechanical or equipment breakdown, unless
such breakdown is caused by acts of God, sudden actions of the elements,
such as floods, hurricanes or tornadoes, sabotage, war or riots. The
foregoing definition of
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force majeure shall apply even if the mechanical or equipment breakdown
occurs without the fault or negligence of Cogenron.
18.1.3 The term force majeure does not include changes in market
conditions or governments action that affect the cost of Cogenerator's
supply of fuel or that affect the cost or availability of any alternate
supplies of fuel or the demand for Cogenron's product. In addition,
force majeure does not include unavailability of equipment, inability to
obtain permits, labor strikes or slowdowns, or failure or unavailability
of transmission capability, unless same is caused by an occurrence which
would fit the definition of force majeure in this Article 18.
18.2 Conditions Upon Force Majeure. If either Party because of force
majeure is rendered wholly or partly unable to perform any of its obligations
under this Agreement, that Party shall be excused from whatever performance is
affected by the force majeure to the extent so affected provided that:
18.2.1 the non-performing Party gives the other Party within
seven (7) days written notice describing the particulars of the
occurrence;
18.2.2 the suspension of performance is of no greater scope and
of no longer duration than is required by the force majeure;
18.2.3 the non-performing Party uses its best efforts to remedy
its inability to perform; and
18.2.4 when the non-performing Party is able to resume
performance of its obligation underthis Agreement, that Party shall give
the other Party written notice to that effect.
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18.3 Limitation of Term. Except as otherwise provided, a Forced Outage
does not relieve Cogenerator of any of its obligations under this Agreement.
18.4 Further Limitation of Term. Except as otherwise provided, in no
event will any condition of force majeure extend this Agreement beyond its
stated term, nor shall any condition of force majeure extend for a time period
greater than one hundred eighty (180) days, except upon the written consent of
TU Electric, which consent will not be unreasonably withheld; provided, however,
that, if the condition of force majeure is not removed within eighteen (18)
months, TU Electric may, at its sole option and discretion, reduce or terminate
this Agreement.
18.5 Additional Limitation of Term. If force majeure is applicable,
whether declared by Cogenron or by TU Electric, TU Electric shall not be
required to make any Capacity Payment for the month(s) or any portions thereof
during the pendency of any event of force majeure.
ARTICLE 19 - GOVERNMENTAL AND REGULATORY BODIES
This Amended and Restated Agreement and all operations hereunder are
subject to the applicable federal and state laws, together with the applicable
ordinances, orders, rules and regulations of any local, state or federal
governmental authority having jurisdiction.
ARTICLE 20 - PRIOR RIGHT TO PURCHASE OR LEASE IN PRIMARY TERM
Cogenron hereby grants to TU Electric a continuing prior right to
purchase or lease the Cogeneration Facility referenced herein, subject only to a
prior right of purchase or lease by Union Carbide Corporation, upon the same
terms and conditions which Cogenron is willing to sell or lease said facility to
an unaffiliated third party. Cogenron shall supply TU Electric in writing with
full details regarding any offer to purchase or lease which Cogenron is willing
to accept, and TU Electric shall
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<PAGE> 72
have sixty (60) days from receipt of such information in which to give Cogenron
notice of its intent to exercise the prior right to purchase or lease granted
herein. In the event that TU Electric elects not to exercise such right,
Cogenron may consummate such sale or lease with said third party within a period
of sixty (60) days from the earlier of TU Electric's election to not exercise
such right or the expiration of the aforesaid sixty (60) day period. If Cogenron
has not fully consummated said sale or lease within such 60-day period, then TU
Electric's prior right to purchase or lease, in respect to any offer by such
third party, will be revived. In any event, TU Electric's prior right to
purchase or lease shall continue to remain in effect, including during said
60-day period, as to any offers of purchase or lease received from unaffiliated
third parties other than that party which initially made the offer of purchase
or lease previously submitted by Cogenron to TU Electric. This Article 20 shall
only apply during the Primary Term.
ARTICLE 21 - LEASE OPTION IN PRIMARY TERM
If this Amended and Restated Agreement is terminated by TU Electric
pursuant to Articles 10.1 (except for 10. 1.7) or 12.2 or, in addition thereto,
by reason of termination for material breach by Cogenron, under Article 15.3, of
Article 15.1.5 or 15.1.8, TU Electric shall have, for a period of sixty (60)
days from and after termination, the option to lease the Cogeneration Facility
from Cogenron for the balance of the term of this Amended and Restated
Agreement. During the term of this Amended and Restated Agreement, either Party
may, by giving notice thereof, require that the Parties diligently and promptly
expedite the preparation of a lease agreement for the Cogeneration Facility, to
become effective upon the exercise by TU Electric of its option. The Parties
understand that it is the present intention of TU Electric to operate the
Cogeneration Facility for peaking service to the TU Electric System under such
lease. Cogenron warrants that said lease agreement shall
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<PAGE> 73
contain each and every provision that will enable TU Electric to operate the
Cogeneration Facility to provide peaking service. Cogenron further warrants that
the rent to be paid by TU Electric under the lease agreement shall be nominal
only and shall include no profit for Cogenron. Cogenron further warrants that it
has the authority to lease the Cogeneration Facility to TU Electric, together
with the real property upon which the Cogeneration Facility is located. Cogenron
warrants that it shall sell to TU Electric, at the then-reasonable market price,
fuel sufficient for TU Electric to operate the Cogeneration Facility for peaking
purposes. If, within six months after notice by a Party for preparation of a
lease agreement, the Parties have not agreed on the terms and provisions of said
lease agreement, the Parties will, unless both agree otherwise, submit to final
and binding arbitration all matters pertaining to the lease agreement upon which
they have not then agreed. Such arbitration, if required, shall occur in Dallas,
Texas and shall be conducted in accordance with the rules of the American
Arbitration Association. This Article 21 shall only apply in the Primary Term.
ARTICLE 21A - RIGHT TO PURCHASE OR LEASE IN SECONDARY TERM
If during the Secondary Term, Cogenron desires to abandon operation of
the Plant, Cogenron shall give TU Electric 180 days prior notice and TU
Electric shall have a continuing and prior right to purchase or lease the Plant
and all associated rights, facilities, appurtenances and properties, free and
clear of any liens, encumbrances or obligation to third parties, upon such terms
and conditions that will allow TU Electric to operate the Plant in a manner to
generate and deliver to TU Electric the capacity and energy contemplated in this
Agreement at a cost that does not exceed the amount of the payments provided
herein. If the Parties have not agreed upon the terms and conditions of such
purchase or lease within 60 days of the date upon which Cogenron plans to
abandon operation of the Plant, Cogenron and TU Electric will, unless both agree
otherwise, submit to final and binding
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arbitration all matters pertaining to such purchase or lease upon which Cogenron
and TU Electric have not then agreed. The rights provided in this Article 2lA
are in addition to all other rights and remedies that may be available to TU
Electric under this Agreement or otherwise and compliance with this Article 21A
is not intended, and shall not be interpreted, to excuse Cogenron in whole or
part from any of its obligations set forth in this Agreement.
ARTICLE 22 - WAIVER
Any waiver at any time by either Party of any of its rights, duties, and
obligations with respect to any default under this Amended and Restated
Agreement, or with respect to any other matters arising in connection with this
Amended and Restated Agreement, shall not be deemed a waiver with respect to any
subsequent default or other matter, whether or not of like or similar nature.
ARTICLE 23 - NO RIGHTS OF THIRD PARTIES
This Amended and Restated Agreement is intended for the benefit of the
Parties hereto. Nothing herein shall be construed to create any duty to, any
standard of care with reference to, or any liability to, any person not a party
hereto, including specifically, but not limited to, Union Carbide Corporation,
Dominion Resources Corporation, Enron Corporation, Calpine Corporation,
Enron/Dominion Cogen Corp., Texas Cogeneration Company and TNP.
ARTICLE 24 - NO PARTNERSHIP
This Amended and Restated Agreement shall not be interpreted or
construed to create an association, joint venture, or partnership between the
Parties or to impose any partnership obligation or liability upon either Party.
Neither Party shall have any fight, power or authority to enter in any
68
<PAGE> 75
agreement or undertaking for, or act on behalf of, or to act as or be an agent
or representative of, or to otherwise bind, the other Party.
ARTICLE 25 - SURETY AGREEMENT
As security for Cogenron's performance under this Agreement, Enron
Corporation, the former parent corporation of Enron/Dominion Cogen Corp.,
executed, contemporaneously with the execution of the June 12, 1985 agreement, a
surety agreement of the same date (as previously amended, modified or otherwise
supplemented). Calpine Corporation (as successor to Enron) and Enron, together
with TU Electric, also executed that Consent and Assignment Agreement dated
August 23, 1997 setting forth the respective obligation of Calpine and Enron. By
its execution below, Enron Corporation hereby consents to this amendment and
restatement of the original June 12, 1985 Agreement, as previously amended and
as further amended herein.
ARTICLE 26 - CONFIDENTIALITY AGREEMENT
This Amended and Restated Agreement is regarded by the Parties to be
confidential and contain proprietary information. Except for such disclosure as
may be compelled by order of court or governmental agency, the Parties agree to
keep confidential and not disclose to any third party: 1) the terms of this
Agreement, or any amendment thereto; 2) any information or material obtained by
one Party from the other pursuant to the terms hereof, including any information
or material obtained through any inspection or audit rights; 3) any information
concerning or relating to the energy and capacity covered by this Agreement, or
the operation of the Cogeneration Facility, or the sales or purchases occurring
or to occur hereunder, or the negotiation of this Agreement. Limited disclosures
of information may be made by one Party hereto with the express written consent
of the
69
<PAGE> 76
other Party, which consent shall specify: 1) the third party to whom such
information may be given; 2) the time when such information is to be given; 3)
the manner in which such information is to be relayed; 4) specific details of
what information is to be given; and 5) any further limitations which the other
Party deems advisable. If requested, the Party desiring to make such a
disclosure shall provide the other Party with a copy of any written documents to
be disclosed, or a copy of a transcript of any oral information to be disclosed,
in order for such other Party to determine whether it will grant or withhold its
consent thereto.
ARTICLE 27 - ENTIRE AGREEMENT
This Amended and Restated Agreement supersedes any and all other
agreements, either oral or in writing, between the Parties hereto with respect
to the subject matter hereof and contains all of the covenants and agreements
between the Parties with respect to said matter. Each Party to this Agreement
acknowledges that no representations, inducements, promises, or agreements,
orally or otherwise, have been relied upon or made by any Party, or anyone
acting on behalf of any Party, which are not embodied herein, and that no other
agreement, statement, or promise not contained in this Amended and Restated
Agreement shall be valid or binding.
ARTICLE 28 - ASSIGNMENT
This Amended and Restated Agreement shall inure to the benefit of, and
be binding upon, TU Electric and Cogenron, together with their respective
successors and assigns, except that neither Cogenron nor TU Electric, nor any
approved assignee or successor of either of said Parties, shall assign its
rights or delegate its duties under this Agreement, or any part of such rights
or duties, without the written consent of the other, and Cogenron shall not
sell, lease or sublease the
70
<PAGE> 77
Cogeneration Facility, or permit the operation thereof by any other party,
without the prior written consent of TU Electric, and any such assignment,
delegation, lease or sublease made without such prior written consent shall be
null and void; provided, however, the requirement of written consent to an
assignment shall not apply to either Party if it merges into, or substantially
all of its assets are acquired by, another entity which is bound by all the
obligations of this Agreement.
ARTICLE 29 - CAPTIONS
AU indices, titles, subject headings, subheadings, article titles and
similar items are provided for the purpose of reference and convenience and are
not intended to be inclusive, definitive or to affect the meaning, contents or
scope of this Amended and Restated Agreement, or any provision hereof.
ARTICLE 30 - AMENDMENTS
This Amended and Restated Agreement can be amended only by mutual
agreement of the Parties set forth in a written document executed by both
Parties.
ARTICLE 31 - CHOICE OF LAWS; VENUE
All questions concerning the interpretation, validity and enforceability
of this Amended and Restated Agreement and of its terms and conditions, as well
as questions concerning the sufficiency or other aspects of performance under
the terms and conditions of this Amended and Restated Agreement, shall be
governed by the laws of the State of Texas, and venue for any disputes arising
hereunder shall he exclusively in Dallas County, Texas. The payment obligations
of Cogenron to TU Electric under this Amended and Restated Agreement are
performable and payable in Dallas, Dallas County, Texas.
71
<PAGE> 78
IN WITNESS WHEREOF, the Parties hereto have caused this Amended and
Restated Agreement to be executed by their duly authorized representatives as of
the date hereinabove set forth, which amends and restates in its entirety that
certain Cogenerated Electricity Sale and Purchase Agreement, dated June 12,
1985.
Cogenron:
COGENRON INC.
By:
-------------------------------------
Earl R. Gore
President and CEO
TU Electric:
TEXAS UTILITIES ELECTRIC COMPANY
By:
-------------------------------------
Steven M. Philley
Director, Energy Supply
Calpine Corporation hereby consents to the amendment and restatement of the
Cogenerated Electricity Sale and Purchase Agreement (as defined in the June 12,
1985 Surety Agreement described below) as set forth in this Amended and Restated
Cogenerated Electricity Sale and Purchase Agreement and hereby agrees and
confirms that Calpine Corporation's obligations as set forth in the Surety
Agreement dated June 12, 1985 between Texas Utilities Electric Company and
Calpine Corporation (as successor-in-interest to Enron Corp., (which is the
successor-in-interest to InterNorth, Inc.) and the Consent and Assignment
Agreement dated June 23, 1997 between Texas Utilities Electric Company, Calpine
Corporation and Enron Corp. remain in full force and effect with respect to the
Primary Term only, and accordingly such obligations shall not apply to the
Secondary Term.
CALPINE CORPORATION
By: /s/ ANN B. CURTIS
------------------------------
Ann B. Curtis
Its: Senior Vice President
----------------------------
72
<PAGE> 79
IN WITNESS WHEREOF, the Parties hereto have caused this Amended and
Restated Agreement to be executed by their duly authorized representatives as of
the date hereinabove set forth, which amends and restates in its entirety that
certain Cogenerated Electricity Sale and Purchase Agreement, dated June 12,
1985.
Cogenron:
COGENRON INC.
By: /s/ EARL R. GORE
-------------------------------------
Earl R. Gore
President and CEO
TU Electric:
TEXAS UTILITIES ELECTRIC COMPANY
By: /s/ STEVEN M. PHILLEY
-------------------------------------
Steven M. Philley
Director, Energy Supply
Calpine Corporation hereby consents to the amendment and restatement of the
Cogenerated Electricity Sale and Purchase Agreement (as defined in the June 12,
1985 Surety Agreement described below) as set forth in this Amended and Restated
Cogenerated Electricity Sale and Purchase Agreement and hereby agrees and
confirms that Calpine Corporation's obligations as set forth in the Surety
Agreement dated June 12, 1985 between Texas Utilities Electric Company and
Calpine Corporation (as successor-in-interest to Enron Corp., (which is the
successor-in-interest to InterNorth, Inc.) and the Consent and Assignment
Agreement dated June 23, 1997 between Texas Utilities Electric Company, Calpine
Corporation and Enron Corp. remain in full force and effect with respect to the
Primary Term only, and accordingly such obligations shall not apply to the
Secondary Term.
CALPINE CORPORATION
By:
------------------------------
Its:
----------------------------
72
<PAGE> 80
Enron Corporation hereby consents to the amendment and restatement of the
Cogenerated Electricity Sale and Purchase Agreement (as defined in the June 12,
1985 Surety Agreement described below) as set forth in this Amended and Restated
Cogenerated Electricity Sale and Purchase Agreement and hereby agrees and
confirms that Enron Corporation's obligations as set forth in the Surety
Agreement dated June 12, 1985 between Texas Utilities Electric Company and Enron
Corporation, (which is the successor-in-interest to InterNorth, Inc.) and the
Consent and Assignment Agreement dated June 23, 1997 between Texas Utilities
Electric Company, Calpine Corporation and Enron Corporation remain in full force
and effect with respect to the Primary Term only, and accordingly such
obligations shall not apply to the Secondary Term.
ENRON CORP.
By: /s/ CLIFFORD BAXTER
------------------------------------
ITS: Senior Vice President
------------------------------------
73
<PAGE> 81
EXHIBIT I- 1987-1988 AVOIDED ENERGY COST
(FOR REDUCED ENERGY PAYMENTS
CALCULATED UNDER ARTICLE 4.6)
The avoided energy cost is to be determined by calculating by time period, using
the Texas Utilities Electric Company's economic dispatch model (or comparable
methodology), the difference between the cost of the total energy furnished by
both Texas Utilities Electric Company and the qualifying facility, computed as
though the energy furnished by the qualifying facility had been furnished by
Texas Utilities Electric Company. This calculation will also be the basis of the
calculation of TUEC's Incremental Lignite Energy Cost.
ENERGY PAYMENTS APPLICABLE FOR
YEARS 1987 - 1988
(FOR ARTICLE 4.3)
<TABLE>
<CAPTION>
Year cent/kwh
---- --------
<S> <C>
1987 3.56
1988 3.74
</TABLE>
In addition to the foregoing amounts, two-tenths (.2) of a mill per KVM shall be
payable by TUEC to Cogenron for energy payments applicable for years 1987-1988.
Exhibit I
PAGE 1 of 2 Pages
<PAGE> 82
ENERGY PAYMENTS APPLICABLE UNDER
ARTICLE 4.4
Applicability. Each of the criteria established in Article 4.4 must be met
before pricing under this section is applicable.
<TABLE>
<CAPTION>
Year cent/KWH
---- --------
<S> <C>
1989 2.22
1990 2.00
1991 2.00
1992 2.11
1993 2.22
1994 2.33
1995 2.66
1996 2.88
1997 2.77
1998 2.88
1999 2.99
</TABLE>
Exhibit I
Page 2 of 2 PAGES
<PAGE> 83
EXHIBIT II - ENERGY PAYMENT APPLICABLE UNDER ARTICLE 4.5
Applicability: The criteria established in Article 4.5 must be met before
pricing under the following formula is applicable:
Incentive Energy Payments ($) =
10.3 MMBtu/MWH x .99 x WACOG of TUEC x [Net Energy - (Contract Level x period
hours x .70)]
Where:
WACOG of TUEC = The monthly weighted average cost of GAS for TU Electric in
dollars per MMBtu.
Period Hours = The number of hours in the current month.
In addition to the Incentive Energy Payments calculated by the above
formula, such Payments shall include two-tenths (.2) of a mill per KWH payable
by TU Electric to Cogenerator.
As used in this exhibit, "MMBtu" shall mean one million (1,000,000)
British thermal units.
Exhibit II
Solo Page
<PAGE> 84
EXHIBIT III - SURETY AGREEMENT
A. Surety Agreement dated and effective June 12, 1985 between InterNorth,
Inc. and Texas Utilities Electric Company.
B. Letter dated July 17, 1985 executed by InterNorth, Inc. and Texas
Utilities Electric Company.
C. Letter dated May 24, 1988 executed by Enron Corp. and Texas Utilities
Electric Company.
D. Consent and Assignment Agreement dated June 23, 1997 between Texas
Utilities Electric Company, Calpine Corporation and Enron Corp.
Exhibit III
Cover Page
<PAGE> 85
EXHIBIT III - SURETY AGREEMENT
A. SURETY AGREEMENT DATED AND EFFECTIVE JUNE 12, 1985 BETWEEN INTERNORTH,
INC. AND TEXAS UTILITIES ELECTRIC COMPANY
Exhibit III-A
Page 1 of 11 Pages
<PAGE> 86
EXHIBIT III
SURETY AGREEMENT
THIS SURETY AGREEMENT ("Surety Agreement") is dated and effective as of
this 12th day of June, 1985, by and between INTERNORTH, INC. ("InterNorth"), a
Delaware corporation having its principal place of business in Omaha, Nebraska,
and authorized to do business in the State of Texas, and TEXAS UTILITIES
ELECTRIC COMPANY ("TUEC"), a Texas corporation having its principal place of
business in Dallas, Texas.
WHEREAS, InterNorth has caused the incorporation of Northern Cogeneration
One Company ("Northern Cogeneration"), a Delaware corporation, as a directly or
indirectly wholly-owned subsidiary of InterNorth, and contemporaneous with the
delivery and effectiveness of this Surety Agreement, Northern Cogeneration and
TUEC have executed that certain Cogenerated Electricity Sale and Purchase
Agreement ("the Cogeneration Agreement") dated as of the date of this Surety
Agreement; and
WHEREAS, under such Cogeneration Agreement Northern Cogeneration
(including its successors or assigns) is obligated pursuant to the terms thereof
to make various money payments to TUEC, including, but not limited to, certain
refund obligations, fees, charges, reimbursement for equipment, services or
facilities indemnification obligations, payments due in the event of a
termination of said agreement or an operational cessation, payments due for
breaches of warranty or for misrepresentations,
Exhibit III-A
Page 2 of 11 Pages
<PAGE> 87
and payments due pursuant to any judgment rendered under or in connection with
said Cogeneration Agreement, together with such other payments which may be or
become due under said Cogeneration Agreement, including any interest accruing on
any of such funds, such payments to be hereinafter collectively referred to as
the "Northern Payment Obligations"; and Northern Cogeneration is subject to
various other obligations of performance under said Cogeneration Agreement; and
WHEREAS, for the reasons and under the terms stated below, InterNorth and
TUEC desire to enter into this Surety Agreement in connection with such
Cogeneration Agreement;
NOW, THEREFORE, for the consideration recited below, InterNorth and TUEC
hereby agree to the terms and conditions of this Surety Agreement whereby
InterNorth, in full recognition of the valuable and substantial benefits which
will accrue to it as a result of the execution and performance of the
Cogeneration Agreement, unconditionally undertakes and assures the performance
of the Northern Payment Obligations, and unconditionally undertakes and assures
the performance of all obligations of Northern Cogeneration under the
Cogeneration Agreement. InterNorth expressly intends that TUEC unconditionally
rely upon this undertaking and assurance in executing the Cogeneration Agreement
and further acknowledges the actual reliance of TUEC o this Surety Agreement in
its execution of the Cogeneration Agreement.
Exhibit III-A
Page 3 of 11 Pages
<PAGE> 88
1. Consideration:
In consideration of the execution by TUEC of the Cogeneration Agreement,
InterNorth does hereby undertake and assure to TUEC, its successors and assigns,
the full, prompt and complete performance by Northern Cogeneration, its
successors and assigns, of all of the Northern Payment Obligations, which
undertaking and assurance are unconditional and absolute. InterNorth agrees that
the undertaking and assurance as set forth herein are and shall be primary
obligations of, and fully and completely enforceable against, InterNorth.
InterNorth acknowledges the receipt and adequacy of the consideration
hereinabove recited and agrees that such consideration fully supports this
Surety Agreement.
2. TUEC's Right to InterNorth's Performance:
It is expressly agreed that, upon any default by Northern Cogeneration,
its successors or assigns, of any of the Northern Payment Obligations or any
portion thereof, as and when due, for any reason whatsoever, TUEC shall be
entitled to performance by InterNorth of the payment of said Northern Payment
Obligations to the same extent as if InterNorth had signed the Cogeneration
Agreement in Northern Cogeneration's place. In addition, upon any default by
Northern Cogeneration, its successors or assigns, in respect to any of its other
obligations as contained in said Cogeneration Agreement, TUEC shall be entitled
to performance by InterNorth of such obligations to the same extent as if
InterNorth had signed the Cogeneration Agreement in Northern Cogeneration's
place.
Exhibit III-A
Page 4 of 11 Pages
<PAGE> 89
3. Effect of Termination, Rescission, Cancellation, or Rejection of
Cogeneration Agreement:
(a) Termination, Rescission or Cancellation. In the event of the
termination of the Cogeneration Agreement pursuant to Articles 10,
12, or 15 thereof, or the rescission of the cogeneration Agreement
in its entirety, or upon any other termination or cancellation of
the co generation Agreement, neither InterNorth nor TUEC shall have
any further liability to the other under this Surety Agreement
except as to any Northern Payment Obligations arising out of
obligations surviving such termination, rescission or cancellation,
or matters occurring prior to such termination, rescission or
cancellation, including, but not limited to, any damages suffered or
which may be suffered by TUEC by reason of any breach of the
Cogeneration Agreement by Northern Cogeneration prior to such
termination, rescission or cancellation.
(b) Rejection. In the event of rejection of the Cogeneration Agreement
by any trustee in bankruptcy, or debtor-in-possession, or receiver,
or by order of any court of competent jurisdiction, InterNorth shall
immediately assume and be liable to perform, as the primary
obligation of InterNorth, all obligations of Northern Cogeneration
under the Cogeneration Agreement, including, but not limited to,
each and all of the Northern Payment Obligations. The terms of such
Exhibit III-A
Page 5 of 11 Pages
<PAGE> 90
Cogeneration Agreement are incorporated herein by reference. In such
event, the Cogeneration Agreement shall continue in effect as to
InterNorth and TUEC, and InterNorth shall be deemed for all purposes
to be in the position of Northern Cogeneration under said agreement,
and InterNorth shall be entitled to the performance of TUEC under
the Cogeneration Agreement unless InterNorth, in any such event,
delegates and assigns such rights and obligations to a designee
capable, in the judgment of TUEC, of performing the obligations
applying to said Northern Cogeneration. In the event of such
delegation and assignment, InterNorth shall nevertheless continue to
be obligated under and bound by this Surety Agreement, which
agreement shall continue in effect as to all of the Northern Payment
Obligations under the cogeneration Agreement. The Northern Payment
Obligations of any designee under the Cogeneration Agreement, as to
which this Surety Agreement shall continue, shall be the same as the
Northern Payment Obligations owed by Northern Cogeneration under the
Cogeneration Agreement prior to such rejection.
4. Waivers of Notices and Defenses:
The obligations of InterNorth hereunder are primary and absolute,
and no notice of default to, or demand for performance by,
InterNorth shall be required of TUEC. TUEC shall not, as a condition
to the liability of InterNorth hereunder, be required
Exhibit III-A
Page 6 of 11 Pages
<PAGE> 91
to:
(i) proceed against Northern Cogeneration or execute upon any
assets of Northern Cogeneration;
(ii) pursue any remedy whatsoever as against Northern Cogeneration.
InterNorth waives any defense arising by reason of any disability of
Northern Cogeneration. Until all indebtedness of Northern Cogeneration to TUEC
has been paid in full, InterNorth has no right of subrogation, and waives any
right to enforce any remedy which TUEC has or may hereafter have against
Northern Cogeneration, and waives any benefit of, and any right to participate
in, any security now or hereafter held by TUEC. No extension of time for
performance, and no alteration, modification or waiver of the obligations
imposed on Northern Cogeneration by the co generation Agreement shall modify,
discharge, or excuse any obligation of InterNorth hereunder.
5. Choice of Law:
The parties expressly agree that all questions and disputes arising out of
or under this Surety Agreement, including, but not limited to, questions and
disputes concerning validity, interpretation, performance, remedies and
enforcement, shall be resolved according to the law of the State of Texas, and
venue for any such dispute shall lie exclusively in Dallas County, Texas. 6.
Limitations on Consolidated Net Worth:
(a) Unless TUEC shall otherwise consent in writing, InterNorth warrants
that, during the entire term of the
Exhibit III-A
Page 7 of 11 Pages
<PAGE> 92
Cogeneration Agreement, the Consolidated Net Worth of InterNorth or
any successor or assignee of the obligations of InterNorth hereunder
shall not be less than Two Hundred Fifty Million Dollars
($250,000,000). TUEC recognizes that during the term of the
Cogeneration Agreement InterNorth may be disposing of all or a
portion of its assets, and TUEC consents to any such disposition on
the condition that InterNorth at all times during the term of the
Cogeneration Agreement causes itself or some other entity having a
Consolidated Net Worth of not less than Two Hundred Fifty Million
Dollars ($250,000,000) to be firmly and unconditionally bound by the
obligations of InterNorth under this Surety Agreement as of the date
hereof. InterNorth agrees that at the time of its designation of any
such other entity as its successor obligor hereunder it will cause
such successor obligor to provide to TUEC: (i) the written agreement
of the successor obligor to fulfill the obligations of InterNorth
hereunder, and (ii) satisfactory evidence that the Consolidated Net
Worth of such successor obligor is not less tan Two Hundred Fifty
Million Dollars ($250,000,000). As used herein, Consolidated Net
Worth means, as of the dat of determination thereof, the sum of the
amounts set forth on a consolidated balance sheet of InterNorth and
its consolidated subsidiaries as of such date prepared in
Exhibit III-A
Page 8 of 11 Pages
<PAGE> 93
accordance with generally accepted accounting principles, as (i)
stockholders equity including capital stock, capital in excess of
par value and retained earnings (or deficit), and (ii) subordinated
debt, less any amounts at which shares of capital stock of
InterNorth or any of its subsidiaries repurchased by InterNorth or
any such subsidiaries appear on such balance sheet.
(b) InterNorth shall deliver to TUEC, within one hundred twenty (120)
days of the end of each calendar year independently audited
consolidated financial statements showing the financial condition of
InterNorth, and certifying that such financial statements present
fairly the consolidated financial condition of InterNorth, and
certifying that such financial statements were prepared in
accordance with generally accepted accounting principles.
(c) In the event of a change either in the method of accounting by
InterNorth or a change in generally accepted accounting principles
which has the effect of increasing or decreasing the Consolidated
Net Worth of InterNorth as reflected in the financial statements of
InterNorth from the amount that would be included therein based on
generally accepted accounting principles followed by InterNorth on
the date of this Surety Agreement, the parties agree to amend the
Exhibit III-A
Page 9 of 11 Pages
<PAGE> 94
provisions of Section 6(a) so that the effect of the restriction
imposed by Section 6(a) is unchanged from that which existed prior
to such change in the method accounting or generally accepted
accounting principles.
(d) InterNorth shall not:
(i) permit North Cogeneration to become less than directly or
indirectly wholly-owned subsidiary through:
(A) merger or consolidation unless the surviving corporation
is a directly or indirectly wholly-owned subsidiary of
InterNorth; or
(B) sale, exchange or transfer, through declaration of a
dividend or otherwise, of the common stock of Northern
Cogeneration.
A wholly-owned subsidiary of InterNorth shall mean a corporation of
which InterNorth owns 100% of the common stock and any other class
of capital stock having voting rights equal to or greater than the
common stock.
7. Successors and Assigns:
This Surety Agreement is binding upon the successors and assigns of
InterNorth.
8. Warranties and Representations:
InterNorth hereby makes unconditionally the following representations and
warranties:
(a) InterNorth is a corporation duly organized and in good standing
under the laws of the State of Delaware, and authorized to do
business in the State of Texas.
Exhibit III-A
Page 10 of 11 Pages
<PAGE> 95
(b) InterNorth has the corporate authority to execute, deliver and fully
perform its obligations under this Surety Agreement and all
resolutions, if any, of directors and shareholders required to
authorize execution and delivery of this agreement have been
obtained.
(c) This Surety Agreement constitutes a valid, legal and binding
obligation of InterNorth enforceable in accordance with its terms.
(d) Execution of and performance by InterNorth under this Surety
Agreement does not require the consent or approval of any person or
governmental agency and does not conflict with or breach any terms
or conditions of:
(i) any order, writ or decree of any court or governmental
authority by which InterNorth is bound; or
(ii) any agreement to which InterNorth is a party or by which it is
bound.
IN WITNESS WHEREOF, the parties hereto have executed this Surety
Agreement as of the day and year first above written.
INTERNORTH, INC.
ATTEST: By: /s/ [SIG]
------------------------------------
Vice President
/s/ [SIG]
- -------------------------
Secretary
TEXAS UTILITIES ELECTRIC COMPANY
ATTEST:
By: /s/ [SIG]
/s/ [SIG] ------------------------------------
- -------------------------
Secretary
Exhibit III-A
Page 11 of 11 Pages
<PAGE> 96
EXHIBIT III - SURETY AGREEMENT
B. Letter dated July 17, 1985 executed by InterNorth, Inc. and
Texas Utilities Electric Company.
Exhibit III-B
Page 1 of 2 Pages
<PAGE> 97
[INTERNORTH LETTERHEAD]
July 17, 1985
Michael D. Spence, President
Texas Utilities Generating Company
400 North Olive, L.B. 81
Dallas, TX 75201
Re: June 12, 1985 Surety Agreement from InterNorth, Inc. to Texas
Utilities Electric Company, Exhibit III to Cogenerated Electricity
Sale and Purchase Agreement between Northern Cogeneration One
Company and Texas Utilities Electric Company, Dated June 12, 1985
In accordance with the request of Texas Utilities Electric Company,
InterNorth, Inc. proposes to amend the captioned Surety Agreement in the
following respects:
a. In the (ii) portion of 6.(a) add the words "to TUEC" between
"evidence" and "that".
b. Immediately following the (ii) portion of 6.(a), add the following
sentence: "Should said entity be unable or unwilling to fulfill the
obligations of this Agreement, InterNorth or its successor entities
shall be liable for fulfillment of these obligations."
If Texas Utilities Electric Company is in agreement with the foregoing,
please sign in the space provided below and return one of the two copies of this
letter amendment to:
Gary D. Hoover
Vice President and General Manager
Cogeneration Business Line
Northern Natural Resources Company
2223 Dodge Street
Omaha, NE 68102
Very truly yours,
INTERNORTH, INC.
By /s/ [SIG]
----------------------------------------
Vice President
Accepted and Agreed to this 6th
day of July, 1985
TEXAS UTILITIES ELECTRIC COMPANY
By /s/ [SIG]
- ----------------------------------------
<PAGE> 98
EXHIBIT III - SURETY AGREEMENT
C. LETTER DATED MAY 24, 1988 EXECUTED BY ENRON CORP. AND TEXAS
UTILITIES ELECTRIC COMPANY.
Exhibit III-C
Page 1 of 5 Pages
<PAGE> 99
[ENRON CORP. LETTERHEAD]
May 24, 1988
Texas Utilities Electric Company
Skyway Tower
400 N. Olive Street, L. B. 81
Dallas, TX 75201
Attn: Mr. Mike Wollitz
Re: Texas City Cogeneration Plant
Gentlemen:
As you know, we have reached an agreement with Dominion Resources, Inc. to
sell its one-half of the outstanding common stock of our subsidiary Enron
Cogeneration Company ("ECC"), which in turn is the parent of Enron Cogeneration
One Company (formerly Northern Cogeneration One Company), the entity with whom
the Electricity Sale and Purchase Agreement was originally executed and which,
with your consent, subsequently assigned that contract to Cogenron, Inc., the
current owner of the Texas City facility. The transactions involved in the sale
to Dominion are described on Exhibit "A", and we hereby formally request your
consent to these transactions (the "Transaction"). We specifically and expressly
reaffirm in all respects the surety obligations set forth in the Surety
Agreement between us dated and effective as of June 12, 1985. The Transaction
will not affect any contractual commitments of Enron Corp.'s subsidiaries to
supply fuel to Cogenron, Inc.
We look forward to an uninterrupted continuation of the working
relationship our companies have enjoyed in the past in connection with the Texas
City Cogeneration Plant.
By /s/ [SIG]
----------------------------------------
We hereby consent to Enron's entering into and consummating the
Transaction.
TEXAS UTILITIES ELECTRIC COMPANY
By /s/ MICHAEL D. SPENCE
-------------------------------------
Name: Michael D. Spence
------------------------------
Title: Division President
------------------------------
Dated: June 15, 1988
--------------------
Exhibit III-C
Page 2 of 5 Pages
<PAGE> 100
Exhibit A
DESCRIPTION OF SALE
BY ENRON CORP. TO DOMINION RESOURCES, INC. OF ONE-HALF
OF THE COMMON STOCK OF ENRON COGENERATION COMPANY
Enron Cogeneration Company ("ECC") is a 95%-owned subsidiary of Enron
Corp. ("Enron") and is the parent of Enron Cogeneration One Company ("ECO"),
which in turn owns all of the outstanding common stock of Cogenron, Inc.
("Cogenron"), which owns the 450 MW cogeneration facility in Texas City, Texas.
Various other subsidiaries of ECC own interests in other cogeneration projects.
Enron has execute a contract (the "Purchase Agreement") with Dominion Resources,
Inc. ("Dominion"), a Virginia corporation, for the acquisition by Dominion of
505 of the common stock of ECC for $90 million in cash, subject to certain
adjustments. Dominion, by virtue of its ownership of an electric utility and a
gas utility, is a public utility holding company under the Public Utility
Holding Company Act of 1935 ("PUHCA"), but is exempt from all the provisions of
PUHCA except Section 9(a)(2) by virtue of the intrastate exemption afforded by
Section 3(a)(1) thereof. As a result of transactions that would occur
contemporaneously with the closing of the Purchase Agreement, each of Dominion
and Enron would own 50% of the outstanding common stock of ECC. ECC would
continue to own all of the stock of ECO, which would in turn continue to own all
of the outstanding common stock of Cogenron. Each of Dominion and Enron will
have the right to designate four members of ECC's board of directors and to
approve significant acts or transactions, either directly or through the vote of
their respective directors. It is contemplated that contemporaneously with the
sale Kenneth L. Lay, the Chairman of the Board of Enron, would become Chairman
of the Board of ECC, and that David Heavenridge, currently a Vice-President of
Dominion, would be ECC's President and Chief Executive Officer.
The Federal Energy Regulatory Commission, in response to Dominion's
Petition for Declaratory Order (docket number EL88-11-000), confirmed that the
acquisition by Dominion of a 50% interest in ECC would not, in and of itself,
threaten the qualified status of any of ECC's cogeneration projects, by adopting
an interpretation of 18 C.F.R. Section 292.206 that when an electric utility or
an electric utility holding company has a direct or indirect equity interest in
a subsidiary that has an ownership interest in a qualifying facility, the
ownership interest attributed to the parent will not exceed the parent's
Exhibit III-C
Page 3 of 5 Pages
<PAGE> 101
proportionate share of the subsidiary's interest in the qualifying facility.
under that interpretation, Dominion's attributed ownership would not exceed 50%
of any of ECC's projects.
Exhibit III-C
Page 4 of 5 Pages
<PAGE> 102
Board of Directors
Enron Corporation
Kenneth L. Lay - Chairman and CEO - Enron
John M. Seidl - President and COO - Enron
Richard D. Kinder - Executive VP, Chief of Staff - Enron
Unnamed
Dominion Resources
Thos. E. Capps - President of Dominion Resources, Inc. and President of
Dominion Energy, Inc.
T. Justin Moore, Jr. - retired Chairman of the Board of Directors of
Dominion Resources, Inc.
*David L. Heavenridge - Vice President - Operations of Dominion Energy,
Inc.
Ronald H. Leasburg - Senior Vice President - Engineering & Construction &
Power Operations (VEPCo)
* will be CEO Enron Cogeneration Company
Exhibit III-C
Page 5 of 5 Pages
<PAGE> 103
EXHIBIT III - SURETY AGREEMENT
D. Consent and Assignment Agreement dated June 23, 1997 between Texas
Utilities Electric Company, Calpine Corporation and Enron Corp.
Exhibit III-D
Page 1 of 9 Pages
<PAGE> 104
CONSENT AND ASSIGNMENT AGREEMENT
THIS CONSENT AND ASSIGNMENT AGREEMENT (this "Agreement"), dated this 23rd
day of June, 1997 (the "Effective Date"), and effective as of such Effective
Date, is made by and among Texas Utilities Electric Company, a Texas corporation
("TUEC"), Enron Corp., a Delaware corporation ("Enron"), and Calpine
Corporation, a Delaware corporation ("Calpine"). TUEC, Enron and Calpine are
referenced in this Agreement individually as a "Party," and collectively as the
"Parties."
W I T N E S S E T H:
WHEREAS, Cogenron, Inc. a Delaware corporation ("Cogenron"), currently
owns a cogeneration plant, producing electricity and steam, together with
related facilities at Texas City, Texas (the "Facility"); and
WHEREAS, TUEC and Cogenron (as assignee of Enron Cogeneration One Company,
formerly known as Northern Cogeneration One Company) have entered into that
certain Cogenerated Electricity Sale and Purchase Agreement, dated as of June
12, 1985 (as amended, restated, modified or otherwise supplemented from time to
time, the "Power Purchase Agreement"); and
WHEREAS, TUEC and Enron (as successor in interest to Internorth, Inc.) are
parties to that certain Surety Agreement, dated as of June 12, 1985 (as amended,
the "Surety Agreement"), pursuant to which Enron has agreed to assure certain
payment and performance obligations of Cogenron under the power Purchase
Agreement; and
WHEREAS, under Section 6(d) of the Surety Agreement, Cogenron may not
become less than an indirect wholly-owned subsidiary of Enron; and
WHEREAS, Cogenron is currently a wholly-owned subsidiary of Enron/Dominion
Cogen Corp., a Delaware corporation ("EDCC"), whose capital stock is owned 505
by Enron Power Corp., a Delaware corporation ("EPC") and a wholly-owned
subsidiary of Enro, and 505 by Dominion Cogen, Inc., a Virginia corporation
("DCI") and wholly-owned subsidiary of Dominion Resources, Inc., a Virginia
corporation ("DRI"); and
WHEREAS, it has been represented by Enron and Calpine that EPC and Calpine
Finance Company, a Delaware corporation ("CFC"), have entered into that certain
Purchase and Sale Agreement, dated as of March 27, 1997 (as amended, the
"Purchase Agreement"), pursuant to which EPC will transfer to CFC all of EPC's
right, title, and interest in the common stock of EDCC owned by EPC, whereby CFC
will become the owner of 50% of the issued outstanding shares of common stock of
EDCC and DCI will remain the owner of 50% of such common stock of EDCC; and
WHEREAS, Enron desires that TUEC consent, and TUEC has agreed to provide
its consent in accordance with the terms of this Agreement, to Cogenron's
becoming the indirect 50% subsidiary of CFC and the indirect 50% subsidiary of
DRI; and
Exhibit III-D
Page 2 of 9 Pages
<PAGE> 105
WHEREAS, such sale of EPC's ownership interest in EDCC is being
consummated pursuant to the Purchase Agreement as of the Effective Date hereof,
and it has been represented by Enron and Calpine that Enron (and/or various
affiliates of Enron) will assign to Calpine (and/or various affiliates of
Calpine) all rights and obligations of Enron (or such affiliates) in and to
certain agreements, including the Surety Agreement, certain of which assignments
are being effected by the terms hereof; and
WHEREAS, Enron and Calpine desire that TUEC consent to the assignment by
Enron to Calpine of Enron's rights and obligations under the Surety Agreement,
and the assumption of such rights and obligations by Calpine, subject to Enron's
continuing liability as provided in this Agreement; and
WHEREAS, the Facility is currently operated by an indirect, wholly-owned
subsidiary of Enron pursuant to an Operations and Maintenance Agreement
(Cogenron Inc.), dated as of August 1, 1995, as amended (the "Original O&M
Agreement"), among Enron Operations Corp. ("EOC"), Cogenron, and EDCC; and
WHEREAS, it has been represented by Enron and Calpine that, as of this
Effective Date, the Original O&M Agreement will be terminated and a new
operations and maintenance agreement is being executed by Cogenron, EDCC and
Calpine (or a subsidiary thereof), as the new operator of the Facility; and
WHEREAS, Enron and Calpine desire to obtain TUEC's consent to such change
in operator of the Facility from EOC to Calpine (or a wholly-owned subsidiary
thereof) pursuant to Article 23 of the Power Purchase Agreement;
NOW, THEREFORE, for good and valuable consideration, the receipt of which
is hereby acknowledged, and intending to be legally bound, each of the Parties
hereto hereby agrees as follows:
SECTION 1. TUEC CONSENT AND LIMITED WAIVER.
1.1 Consent. Subject to the terms and conditions set forth herein, TUEC
hereby: (i) acknowledges Enron's and Calpine's representations that, immediately
after giving effect to the transactions contemplated by the Purchase Agreement,
CFC and DRI will each own 50% of the issued and outstanding shares of the common
stock of EDCC, and that Cogenron will be an indirect 50% subsidiary of Calpine
and indirect 50% subsidiary of DRI, (ii) so long, and only so long, as Calpine
owns at least a direct or indirect 50% ownership interest in Cogenron (or its
successors or assigns): (a) waives the requirement in Section 6(d) of the Surety
Agreement that Cogenron (or its successors and assigns) be a direct or indirect
wholly-owned subsidiary of Enron, and (b) agrees that the sale of EPC's
ownership interest in EDCC to CFC pursuant to the Purchase Agreement ill not be
a breach of the Surety Agreement; provided that TUEC has not reviewed said
Purchase Agreement and, therefore, TUEC's consent cannot extend to any matter
under the Purchase Agreement other than the sale of stock as has been
represented by Enron and Calpine to TUEC, (iii) consents to the assignment
pursuant to the terms hereof by Enron to Calpine of Enron's rights and
obligations under the Surety Agreement, subject to the continuing liability of
Enron as set forth in Section 2.2 of this Agreement, and (iv) consents to the
change in operator of the Facility from EOC
Exhibit III-D
Page 3 of 9 Pages
<PAGE> 106
to Calpine (or a wholly-owned subsidiary of Calpine). Neither Enron, Calpine,
nor TUEC shall be deemed to have waived, released, relinquished, modified or
qualified any of their respective rights or remedies under the Surety Agreement
by virtue of this Agreement, except as specifically set forth herein.
SECTION 2. ASSIGNMENT AND ASSUMPTION.
2.1 Assignment and Assumption. As of this Effective Date, Enron hereby
does grant, transfer and assign to Calpine all of its respective rights,
interests and obligations under the Surety Agreement and Calpine hereby accepts
and assumes all such rights, interests and obligations of Enron under the Surety
Agreement. From and after this Effective Date hereof, Calpine shall perform the
obligations, and inure to any benefit, of Enron under the Surety Agreement, and
Calpine agrees to be bound by all of the terms of the Surety Agreement assigned
to and assumed by Calpine in every way as if an original party thereto.
2.2 Effect of Assignment and Assumption: Extension of Power Purchase
Agreement. Prior to this Effective Date, all undertakings and assurances of
Enron under the Surety Agreement shall remain the unconditional and absolute
primary obligations of Enron. From and after this Effective Date, all
undertakings and assurances of Enron under the Surety Agreement shall be the
unconditional and absolute obligations of each Calpine and Enron.
Notwithstanding anything herein to the contrary, as of this Effective Date,
Calpine shall have primary liability for performance under the Surety Agreement,
it being agreed that Enron shall only be required to perform thereunder after it
has received written notice from TUEC that Calpine has failed to perform under
the Surety Agreement within five days after a demand to so perform was made upon
Calpine, or its permitted successors or assigns, by TUEC, or its permitted
successor assigns. In the event that the Power Purchase Agreement is extended
beyond its current termination dat of June 30, 1999, the Parties acknowledge and
agree that Enron's liability after June 30, 1999 shall be limited to the
obligations of Enron as stated in this Section 2.2 solely for events or
conditions occurring prior to June 30, 1999 and in no event will Enron be liable
for events or conditions under the Power Purchase Agreement which occur after
said date of June 30, 1999, with Enron's liability continuing after said date of
June 30, 1999, as to any events or conditions occurring prior to June 30, 1999,
as stated in accordance with this Section 2.2.
SECTION 3. REPRESENTATIONS.
Each of the Parties hereto represents and warrants to each of the other
Parties hereto, that (a) it is a corporation duly incorporated, validly existing
and in good standing under the laws of its jurisdiction of incorporation, (b) it
has all requisite corporate power and authority to execute, deliver, and perform
its obligations under this Agreement, (c) it has taken all necessary corporate
action (including any necessary stockholder action) to authorize it to execute,
deliver and perform this Agreement in accordance with its terms, (d) it has duly
executed and delivered this Agreement, and (e) this Agreement is the valid and
binding obligation of such Party, enforceable in accordance with its terms,
subject to applicable bankruptcy, insolvency and other similar laws relating to
or affecting the enforcement of creditors' rights generally and to general
principles of equity.
Exhibit III-D
Page 4 of 9 Pages
<PAGE> 107
SECTION 4. MISCELLANEOUS.
4.1 Further Assurances. TUEC hereby agrees to execute and delivery all
such instruments and to take all such action as may be necessary to effectuate
fully the purposes of this Agreement.
4.2 Governing Law. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE
PARTIES HEREUNDER SHALL BE CONSTRUED IN ACCORDANCE WITH AND BE GOVERNED BY THE
LAWS OF THE STATE OF TEXAS (WITHOUT GIVING EFFECT TO THE PRINCIPLES THEREOF
RELATING TO CONFLICTS OF LAW).
4.3 Counterparts. This Agreement may be executed in any number of
counterparts and by the different Parties hereto on separate counterparts, each
of which when so executed and delivered shall be an original, but all of which
shall together constitute one and the same instrument.
4.4 Headings Descriptive. The headings of the several sections and
subsections of this Agreement are inserted for convenience only and shall not in
any way affect the meaning or construction of any provision of this Agreement.
4.5 Severability. In case any provision in or obligation under this
Agreement shall be invalid, illegal or unenforceable in any jurisdiction, the
validity, legality and enforceability of the remaining provisions or
obligations, or of such provision or obligation in any other jurisdiction, shall
not in any way be affected or impaired thereby.
4.6 Amendment, Waiver. Neither this Agreement nor any of the terms
hereof may be terminated, amended, supplemented, waived or modified except by an
instrument in writing signed by each of the Parties hereto. This Agreement is
for the specific purpose for which given and shall not preclude any other or
future Agreement that may be required under the Surety Agreement nor shall any
such other or future Agreement be deemed to be required as a result of this
Agreement.
4.7 Successors and Assigns. This Agreement shall be binding upon, and
shall inure to the benefit of, each of the Parties hereto and their respective
permitted successors and assigns. As used in this Agreement, "permitted
successors and assigns" refers to any party permitted to be a successor or
assign under the Surety Agreement.
4.8 Entire Agreement. This Agreement embodies the entire agreement among
the Parties hereto relating to the subject matter hereof and supersede all prior
agreements, representations and understandings, if any, relating to the subject
matter hereof.
4.9 Additional Enron Covenant. Enron and TUEC acknowledge that TUEC and
Cogenron have been engaged in discussions concerning the Power Purchase
Agreement with respect to potential respective liabilities for costs, fees and
losses associated with the transmission of electric capacity and energy from the
Facility to TUEC's Delivery Point under the Power Purchase Agreement (the
"Transmission Charges") which have accrued subsequent to the implementation of
revised Substantive rules promulgated by the Public Utility Commission of Texas
providing for open access transmission service. Enron agrees that, commencing
with the date of this Agreement, and continuing through June 30, 1999, neither
it nor any of its affiliates or subsidiaries will take any action
Exhibit III-D
Page 5 of 9 Pages
<PAGE> 108
adverse or that could be adverse to TUEC's position with respect to the
liability of the respective parties to the Power Purchase Agreement (or any
surety thereof) for the Transmission Charges, and Enron represents that neither
it nor any of its affiliates or subsidiaries ( other than Cogenron's previous
discussions with TUEC concerning Cogenron's disagreement as to the Transmission
Charge issue) have taken any such action prior to the date of this Agreement;
provided, however, Enron or any of its affiliates or subsidiaries may file a
response in respect to, or intervene in, proceedings before any state, local, or
federal regulatory or judicial body if any such proceeding concerns or relates
to liability for transmission charges other than those referenced in the Power
Purchase Agreement, and other than those concerning or relating to power
transmitted pursuant to the Power Purchase Agreement. Additionally, Enron agrees
on behalf of itself and its affiliates and subsidiaries to not initiate, file a
response to, or intervene in any proceeding concerning or relating to any issue
having to do with reformation of the Power Purchase Agreement, and Enron
represents that neither it nor any of its affiliates or subsidiaries have
previously done so. The Parties acknowledge that nothing herein is indicative of
Cogenron's position or views with respect to the Transmission Charges, and,
further, that as of this Effective Date, Cogenron will cease to be either an
affiliate or subsidiary of Enron.
4.10 Legal Fees. Enron agrees to pay to TUEC within 20 days of the date
hereof the sum of $20,000 as reimbursement of legal fees and expenses in
connection with this transaction.
REMAINDER OF
THIS PAGE INTENTIONALLY LEFT BLANK
Exhibit III-D
Page 6 of 9 Pages
<PAGE> 109
IN WITNESS WHEREOF, each of the Parties hereto has caused this Agreement
to be duly executed and delivered by its duly authorized officer as of the date
hereof, also referenced herein as the Effective Date.
TEXAS UTILITIES ELECTRIC COMPANY
By: /s/ HENRY A. BUNTING
-------------------------------------
Name: Henry A. Bunting
---------------------------------
Title: Manager, Resource Acquisition
---------------------------------
ENRON CORP.
By:
-------------------------------------
Name:
---------------------------------
Title:
---------------------------------
CALPINE CORPORATION
By:
-------------------------------------
Name:
---------------------------------
Title:
---------------------------------
The undersigned hereby executes this Agreement solely for the purpose of
agreeing and consenting to any termination or reduction of Enron's obligations
under the Surety Agreement effectuated hereby, pursuant to Section 5.11 of that
certain Purchase Agreement, dated May 4, 1988, as amended, between Enron and
DRI.
DOMINION RESOURCES, INC.
By:
----------------------------
Name:
--------------------------
Title:
-------------------------
Exhibit III-D
Page 7 of 9 Pages
<PAGE> 110
IN WITNESS WHEREOF, each of the Parties hereto has caused this Agreement
to be duly executed and delivered by its duly authorized officer as of the date
hereof, also referenced herein as the Effective Date.
TEXAS UTILITIES ELECTRIC COMPANY
By:
-------------------------------------
Name:
---------------------------------
Title:
---------------------------------
ENRON CORP.
By: /s/ [SIG]
-------------------------------------
Name: [ILLEGIBLE]
---------------------------------
Title: SR. VICE PRESIDENT
---------------------------------
CALPINE CORPORATION
By: /s/ RON A. WALTER
-------------------------------------
Name: Ron A. Walter
---------------------------------
Title: Vice President
---------------------------------
The undersigned hereby executes this Agreement solely for the purpose of
agreeing and consenting to any termination or reduction of Enron's obligations
under the Surety Agreement effectuated hereby, pursuant to Section 5.11 of that
certain Purchase Agreement, dated May 4, 1988, as amended, between Enron and
DRI.
DOMINION RESOURCES, INC.
By:
----------------------------
Name:
--------------------------
Title:
-------------------------
Exhibit III-D
Page 8 of 9 Pages
<PAGE> 111
IN WITNESS WHEREOF, each of the Parties hereto has caused this Agreement
to be duly executed and delivered by its duly authorized officer as of the date
hereof, also referenced herein as the Effective Date.
TEXAS UTILITIES ELECTRIC COMPANY
By:
-------------------------------------
Name:
---------------------------------
Title:
---------------------------------
ENRON CORP.
By:
-------------------------------------
Name:
---------------------------------
Title:
---------------------------------
CALPINE CORPORATION
By: /s/ RON A. WALTER
-------------------------------------
Name: Ron A. Walter
---------------------------------
Title: Vice President
---------------------------------
The undersigned hereby executes this Agreement solely for the purpose of
agreeing and consenting to any termination or reduction of Enron's obligations
under the Surety Agreement effectuated hereby, pursuant to Section 5.11 of that
certain Purchase Agreement, dated May 4, 1988, as amended, between Enron and
DRI.
DOMINION RESOURCES, INC.
By: /s/ THOMAS F. FARRELL
----------------------------
Name: Thomas F. Farrell, II
--------------------------
Title: Senior Vice President
-------------------------
Exhibit III-D
Page 9 of 9 Pages
<PAGE> 1
Exhibit 10.11.6
AGREEMENT FOR THE PURCHASE OF
ELECTRICAL POWER AND ENERGY
BETWEEN
CAPITOL COGENERATION COMPANY, LTD.
AND
TEXAS-NEW MEXICO POWER COMPANY
POWER AGREEMENT
<PAGE> 2
AGREEMENT FOR THE PURCHASE OF ELECTRICAL POWER AND
ENERGY FROM CAPITOL COGENERATION COMPANY, LTD.
BY TEXAS-NEW MEXICO POWER COMPANY
WHEREAS, Capitol Cogeneration Company, Ltd. (CCC) plans to operate a
cogeneration facility (the "Facility") located on the Celanese Chemical Company
plant site at Pasadena, Texas, said facility to have capability for generating
approximately 375 MW of electric output; and
WHEREAS, CCC has entered into an Application and Agreement for Purchase of
Cogenerated Electricity with Houston Lighting and Power Company (HL&P) for the
supply and sale of electrical output from the Facility; and
WHEREAS, Texas-New Mexico Power Company (TNP) operates a distribution utility
plant in Galveston and Brazoria County, Texas, and at other locations in Texas
and New Mexico, and purchases power for distribution to its retail customers;
and,
WHEREAS, CCC may at some future date wish to sell to TNP all or a part of its
electrical output capability which is not purchased by HL&P when arrangements
for such sale to TNP are agreed upon pursuant to this Agreement;
NOW THEREFORE, CCC and TNP (Party or Parties) do hereby agree as follows:
<PAGE> 3
ARTICLE I. CONDITIONS OF SALE
TNP agrees to purchase whatever amount of the electrical power output of the
Facility owned by CCC is tendered to TNP by CCC, subject to the following
conditions:
1) It will be the responsibility of CCC to reimburse TNP for all
interconnection costs, if any, required for TNP to accomplish the Facility's
delivery of electrical power into TNP's transmission system at the time of the
first such delivery and sale. Interconnection costs will include the total cost
of improvements or revisions to the TNP transmission system as well as
improvements or revisions to systems belonging to either CCC or to the system of
any other electric utility over which power flows. Costs shall include all
improvements or revisions to relaying or communication systems associated with
above transmission systems and improvements or revisions to metering which may
be required for TNP to accept power delivery. TNP shall have the responsibility
of obtaining the consent of any other electric utilities with which
interconnection is required and shall be responsible for any wheeling agreements
and for payment of any wheeling charges associated with its receipt of power
hereunder. TNP will accept the delivery of power by CCC after 90 days prior
written notice by CCC to TNP, subject to the following:
a) The acceptance of power delivered by CCC will actually
commence whenever the system improvements or revisions to
2
<PAGE> 4
be done by CCC as required are completed such that the physical flow of
the power from CCC to TNP's system can be accomplished. b) On receipt of
the above written notice from CCC by TNP, TNP will immediately undertake
to accomplish any system improvements or revisions on its own system and
will advise CCC of any required improvements or revisions on the CCC
system or on the system of another utility and TNP will proceed
immediately, if required, to contract with any other utility so that
revisions or improvements on the other utility's system can be made.
ARTICLE II. PAYMENT FOR COGENERATED POWER
TNP will pay to CCC Ninety-Eight Percent (98%) of the cost which TNP actually
avoids from a supplying utility or utilities by purchasing the power from CCC as
an alternative to taking the same amount of power supply from the electric
utility or utilities which would otherwise supply the wholesale power to TNP.
The determination of actual cost avoided from a supplying utility or utilities
will be calculated as provided in Exhibit "A", attached hereto and made a part
of this Agreement.
All costs as determined according to Exhibit "A" are to be determined using the
tariff(s) of the supplying utility or utilities in effect for the period during
which deliveries of power occurred. All tariffs are subject to change upon
approval of the appropriate regulatory authority. TNP agrees to pay or cause to
be paid to CCC monthly, the amount as described above within 20 days from
3
<PAGE> 5
the receipt of invoice. TNP also agrees to furnish any information necessary to
the determination of said costs. When necessary, adjustments to billings will be
made such that fuel usage to produce electric power and energy will coincide
with the period for which billings are calculated.
ARTICLE III. INTERCONNECTION STANDARDS
CCC must meet the following interconnection standards:
1) The voltage supplied by the Facility will be that voltage normally
available on TNP's transmission system at the Facility's site, or such
other standard voltage as may be agreed to by the CCC and TNP, and is in
compliance with A.N.S.I. Standard C 84.1 and other applicable codes and
standards.
2) The frequency of electricity supplied will be 60 hertz.
3) The number of phases of the produced voltage will be compatible with
the phase (phases) available on TNP's system at the Facility site.
Normally the number of phases shall be the same as those of TNP's system.
4) The protective devices connected between the output of the Facility
and TNP's system must be rated for the maximum available fault current
which the Facility or TNP's system may be capable of developing at the
point of interconnection. Such devices shall disconnect the Facility's
generation from TNP's system in the event of a fault on the system
4
<PAGE> 6
belonging to the Facility in order to maintain continuity of service to
other customers connected to other portions of TNP's system.
5) The Facility generator output will not affect TNP's distribution
system. This includes, but is not limited to:
Overload of distribution equipment
Abnormal harmonic voltages
Interference with automatic voltage regulation equipment
Electronic noise that would interfere with communications
6) The Facility's system shall be capable of protecting itself from
damage resulting from impact loading and/or overloading under both normal
operating and emergency conditions. This shall include the ability to
synchronize on connecting to TNP's system to avoid voltage decay or out of
phase connection. a) The controls of the Facility shall be capable of
disconnecting the Facility's input to TNP or otherwise limiting the
Facility's input to avoid overload of any of TNP's system components or
undesirable transient voltage or frequency fluctuations in the event of a
fault on TNP's system or under conditions of large motor start or
capacitor switching operations on TNP's system to which the Facility is
interconnected. This device must be coordinated with TNP's protective
system.
ARTICLE IV. SAFETY STANDARDS
CCC must meet the following safety standards:
5
<PAGE> 7
1) The Facility's interconnection must meet the requirements of the
National Electrical Safety Code, National Electric Code and any applicable
local codes.
2) The Facility's interconnection must automatically disconnect from
TNP's system if TNP's service is interrupted during emergency conditions.
Pursuant to the PUC's rules, TNP may discontinue service to or from the
Facility it has been determined that continuation of service would
contribute to such emergency. CCC will coordinate automatic
re-energization in this system with TNP's standard protection practices.
3) There must be a disconnect between the Facility interconnection and
TNP which can be controlled and operated by TNP. This disconnect must
provide a visible air gap which will assure disconnection before a TNP
employee does any work on the circuit or circuits to which the
interconnection is made.
ARTICLE V. FORCE MAJEURE
Neither party shall be held responsible or liable for any loss or damage
resulting from failure to perform its obligations hereunder due to any cause
beyond its control which the party could not reasonably be expected to avoid.
6
<PAGE> 8
ARTICLE VI. NOTICES
Any written notice required hereunder shall be deemed properly made, given to,
or served upon the party to whom it is directed when sent by United States Mail,
postage prepaid, addressed to the President, or other representative designated
in writing by the party being notified.
ARTICLE VII. WAIVERS
A waiver by either party of its rights with respect to any matter arising in
connection with this Agreement, shall not be deemed a waiver with respect to any
subsequent matter. Any delay, short of the statutory period of limitations, in
asserting or enforcing any right shall not be deemed a waiver of such right.
ARTICLE VIII. NO DEDICATION OF FACILITIES
An undertaking by one party to another party under any provision of this
Agreement shall not constitute the dedication of the system or any portion
thereof of the party to the public or to the other party, and any such
undertaking shall cease upon the termination of the party's obligation
hereunder.
ARTICLE IX. NO THIRD PARTY RIGHTS
Unless otherwise specifically provided in this Agreement, the parties do not
intend to create rights in or to grant remedies
7
<PAGE> 9
to any third party as a beneficiary of this Agreement or of any duty, covenant,
obligation or undertaking established hereunder.
ARTICLE X. GOVERNING LAW
This Agreement shall be governed by and construed in accordance with the laws of
the State of Texas as if the Agreement were to be performed wholly in the State
of Texas.
ARTICLE XI. COMMISSION APPROVAL
This Agreement, and all obligations hereunder, are expressly conditioned upon
the granting of such approval and authorization by any Commission or other
regulatory body whose approval or authorization may be required by law from time
to time.
ARTICLE XII. ASSIGNMENT
This Agreement shall inure to the benefit of and be binding upon the parties
hereto, their successors and assigns. This Agreement may only be assigned with
the consent of the parties hereto.
ARTICLE XIII. LIABILITY
Neither party shall be liable for any injury or death to person or damage to
property (including consequential damage) suffered or claimed by the other party
or by the party's directors, officers, employees, agents or customers as a
result of the other party's
8
<PAGE> 10
performance or non-performance of this Agreement, whether due to such other
party's negligence or otherwise, and each of the parties shall indemnify and
hold harmless the other party against any such liability and all costs and
expenses in connection therewith. The foregoing provision shall not however,
relieve any insuror of its obligations under any insurance policy under which a
party hereunder is the insured, but the insuror shall not have any subrogation
rights against the other party hereunder if such other party is the Indemnitee
and the insured is the Indemnitor.
ARTICLE XIV. TERM OF AGREEMENT
This Agreement shall extend for a primary period of Eleven (11) years from the
date hereof, and afterwards for such time as CCC is able to provide power to
TNP.
CAPITOL COGENERATION COMPANY, LTD.
By its General Partners
Attest: CAPITOL POWER, INC.
[SIG] By: [SIG]
- ---------------------------- -------------------------------------
8/31/83
Attest: BAYPORT COGENERATION, INC.
[SIG] By: [SIG]
- ---------------------------- -------------------------------------
August 31, 1983
Attest: TEXAS-NEW MEXICO POWER, INC.
[SIG] By: [SIG]
- ---------------------------- -------------------------------------
August 31, 1983
9
<PAGE> 11
EXHIBIT A
AVOIDED COST
Avoided Cost can be expressed with the formula:
Avoided Cost = S(1) - S(2) - (W+B+L)
Where:
S(1) = total cost of a given amount of power from TNP's utility supplier.
This normally included a capacity charge stated in $/KVA or $/KW,
energy charges in $/KWH and a customer charge. The amount of power
would be that actually supplied to TNP by the utility supplier or
other QF's plus that supplied to TNP by CCC.
S(2) = total cost of power actually supplied by TNP's utility supplier.
This would exclude the power taken by TNP from CCC or other QF's.
W = wheeling costs paid by TNP to other utilities to transport power
from CCC to the TNP system.
B = backup charges, if any, paid by TNP to other utilities for power
to supply TNP's retail customers when CCC cannot provide delivered
power.
L = cost to TNP of additional losses, if any, to deliver CCC power to
TNP systems as opposed to losses incurred when purchasing from a
utility supplier of wholesale power.
FOR INFORMATION PURPOSES: portions of S(1) and S(2) above are determined using
capacity payments made by TNP. When C(B) is GREATER THAN C, a ratchet charge is
being paid to a supplier.
C = capacity actually purchased from utility supplier during month
stated as $/KVA or $/KW using monthly metered or scheduled power
times the supplying utility's capacity charge per KVA or KW.
C(B)= capacity being billed by utility supplier during month. Ratchet
applications in suppliers' tariffs determine the billing capacity in
any month as a percentage of the actual capacity taken during some
prior peak period. Charges are stated as $/KVA or $/KW.
<PAGE> 12
Ratchets are subject to change with suppliers' future filings of rate cases.
Ratchets as of the date of this agreement are:
UTILITY & APPLICATION
- ------- ----- -----------
HL&P 75 May 15 - Oct 15
TP&L 65 June - October
TESCO 80 June - October
WTU 0 N/A
SWPS 65 Preceding 11 months
<PAGE> 13
[TEXAS-NEW MEXICO POWER COMPANY LETTERHEAD]
August 14, 1986
Mr. C. Linn Maurer Mr. J. M. Tarpley
CAPITOL POWER, INC. BAYPORT COGENERATION CO., INC.
P. O. Box 21130 P. O. Box 2943
San Antonio, TX 78285 Fort Worth, Texas 76109
Mr. Charlie Ebrom Mr. Rickey J. Wright
CAPITOL POWER, INC. BAYPORT COGENERATION CO., INC.
P. O. Box 21130 P. O. Box 2943
San Antonio, TX 78285 Fort Worth, Texas 76109
Gentlemen:
This Letter Agreement is for the purpose of setting out binding Agreements
previously made between Capitol Cogeneration Company Limited (CCC) and Texas-New
Mexico Power Company (TNP) (hereinafter, the Parties). The Parties affirm and
agree that all points listed below are, and shall continue to be, binding on the
Parties by CCC and TNP supplement and/or replace the below detailed Agreements
and understandings.
1. TNP will purchase capacity in the maximum amount of 300 MW from CCC.
TNP will contract for standby capacity for use in the event the
capacity provided by CCC or another cogenerator is unavailable. The
amount of standby capacity anticipated by TNP is presently 125 MW,
which amount is adequate to standby the single largest generating
unit now operated by cogenerator's selling power to TNP. The cost of
such standby service will be pro-rated by TNP among the
cogenerator's selling capacity to TNP. The proration is based on the
maximal amount of capacity contracted for with each cogenerator.
CCC's prorated amount of cost will be subtracted from the cost
avoided by TNP from its suppliers due to purchasing capacity from
CCC, and reflected as a reduction in the avoided cost paid to CCC by
TNP.
2. That certain contract signed August 31, 1983 and titled Agreement
for the Purchase of Electrical Power and Energy between CCC and TNP
(Contract) provides for TNP to purchase all of the energy offered to
TNP by CCC. Under Article XI of the Contract, the content is made
subject to regulatory bodies having regulatory control. TNP
currently has approved by a regulatory body (i.e. The Public Utility
Commission of Texas) specific rules and regulations covering TNP's
energy purchases from Cogenerator's. The Parties acknowledge that
the attached rules and regulations apply to purchases by TNP of CCC
energy until such rules and regulations are approved in an altered
form by the Public Utility Commission of Texas.
<PAGE> 14
Management Committee Members
August 14, 1986
Page #2
3. Article XIV of the Contract provides for a primary term of 11 years
beginning with the date of Contract with extensions of said Contract
for as long as CCC can supply capacity or energy to TNP. The Parties
acknowledge that the capacity and energy supplied to TNP for the
primary Term of Contract or capacity and energy that might be
supplied to TNP after the primary term of Contract is subject to
TNP's actual need for capacity at the time CCC offers such capacity
or energy. The Parties further agree that once a specific amount of
capacity is supplied to TNP by CCC during the primary term such
capacity can only be withdrawn from TNP for force majeure reasons
unless the withdrawal is agreed to by TNP. For capacity which CCC
wishes to sell to TNP after the primary term CCC agrees that the
Parties will enter into a specific agreement concerning the period
of time such capacity is to be made available to TNP beyond the end
of the primary term with such agreement to be reduced to writing and
signed by the Parties no later than three (3) years before the end
of the primary term. Nothing in this paragraph shall prevent TNP
from agreeing to release capacity at TNP's sole option, however it
is understood that once capacity is released for CCC to sell to
others, TNP will have the sole option and responsibility to accept
or reject any re-offered capacity based on system needs and
requirements.
TEXAS NEW-MEXICO POWER COMPANY
/s/ JAMES M. TARPLEY
------------------------------------
James M. Tarpley
Executive Vice-President
Capitol Cogeneration
/s/ LINN MAURER /s/ JAMES M. TARPLEY
- ------------------------------- ------------------------------------
Linn Maurer, President James M. Tarpley, President
Capitol Power, Inc. (Partner) Bayport Cogeneration Co., Inc. (Partner)
/s/ CHARLES EBROM /s/ RICKEY WRIGHT
- ------------------------------ ------------------------------------
Charles Ebrom, Vice President Rickey Wright, Manager
Capitol Power, Inc. (Partner) Bayport Cogeneration Co., Inc. (Partner)
<PAGE> 15
TERMS AND CONDITIONS
LOAD AVAILABLE TO COGENERATORS
The amounts of load at each point of supply to TNP available for supply by
cogenerators is subject to the following:
a. Ratchet provisions in the tariffs of suppliers.
b. Minimum demand provisions for TNP at each delivery point in
accordance with the wholesale contracts of TNP's suppliers.
c. Provisions affecting TNP's purchase of cogenerated power in the
supplier tariffs as approved by the Public Utility Commission of
Texas and/or the Federal Energy Regulatory Commission.
d. Supply not in excess of the actual demands.
ENERGY PURCHASES
The purchase of cogenerated energy by TNP will be subject to the
following:
a. The first priority for delivery of energy will be extended to a
cogenerator who is contracted to supply firm capacity to TNP. The
amount of energy to be supplied by each cogenerator in this category
can be equal to the contracted capacity delivered at 100% load
factor, subject to TNP's load at the time.
b. The next priority for determination of the amounts of energy to be
supplied by a cogenerator will be in accordance with the price at
which the energy is offered and delivered by the cogenerator.
c. If the delivered prices for all energy offered in "b" above are
equal and all energy requirements cannot be satisfied through "a"
above, then the remaining energy requirements of TNP shall be
apportioned to the available cogenerators not offering firm
capacity, prorated on the total amount of energy offered by each
cogenerator.
d. Under no circumstances will TNP accept energy (KWH) into its system
in excess of that required to serve its loads, except for energy
which TNP has contracted to wheel to another utility and which the
other utility will take in a given hour. Arrangements between a
cogenerator and other utility, for said deliveries, are wholly the
responsibility of the cogenerator and the other utility and are in
no way the responsibility of TNP. When arrangements have been
completed for deliveries of energy between a cogenerator and another
utility, TNP shall provide the wheeling service subject to contract.
<PAGE> 16
STANDBY SERVICE TO TNP
TNP must make arrangements for Standby Service in order to accommodate
purchases of firm power from a cogenerator. If such conditions do not exist
through tariff provisions of wholesale suppliers to insure firm deliveries,
Standby Service will be negotiated if available, by and for TNP. Any cost
associated with functions necessary to maintain a firm supply of power to TNP
will be allocated as a adjustment to payments made to cogenerator requiring the
acquisition of such Standby Service.
The amount of Standby Service necessary shall be determined by TNP based
on unit sizes, diversity, scheduling, and evaluation of quality of service.
<PAGE> 17
AGREEMENT SUBSTITUTING A PARTY
This Agreement among Capitol Cogeneration Company, Ltd., a Texas limited
partnership ("CCC"), Clear Lake Cogeneration Limited Partnership, a Texas
limited partnership ("Purchaser"), and Texas-New Mexico Power Company, a Texas
corporation ("TNP").
W I T N E S S E T H :
WHEREAS, CCC and TNP are parties to an agreement for purchase of
electrical power and energy attached hereto, incorporated herein by this
reference and referred to as the "Power Agreement";
WHEREAS, Purchaser has executed an Asset Sale Agreement (the "Asset Sale
Agreement") dated as of April 7, 1988, for the purchase of substantially all the
assets of CCC, including the cogeneration facility located at Celanese Chemical
Company, Inc.'s Clear Lake Chemical Plant in Harris County, Texas, as more fully
described in the Asset Sale Agreement (the "Facility");
WHEREAS, contemporaneously with the closing of the Asset Sale Agreement,
CCC desires to transfer and assign to Purchaser all of CCC's rights, title and
interest in and to the Power Agreement;
WHEREAS, in connection with financing the acquisition contemplated by the
Asset Sale Agreement, Purchaser intends to assign collaterally all of its
rights, title and interest in and to the Power Agreement to one or more
financial institutions (individually or collectively, the "Lender") as security
for Purchaser's repayment of amounts advanced by such Lender to Purchaser; and
WHEREAS, Purchaser hereafter may wish to transfer and assign all of its
rights, title and interest in and to the Power Agreement to an affiliated
entity.
NOW, THEREFORE, in consideration of the mutual covenants contained herein,
the parties agree as follows:
1. Subject to all the terms and conditions of this Agreement, Purchaser
is hereby substituted for CCC as a party to the Power Agreement.
2. From and after the date hereof, with respect to the Power Agreement,
Purchaser shall succeed to all of the rights of CCC, Purchaser shall
assume the obligations of CCC and TNP shall look solely to Purchaser
for any
<PAGE> 18
obligations and liabilities under the Power Agreement arising from
and after the date hereof. TNP shall look solely to CCC and its
general partners for any obligations and liabilities under the Power
Agreement arising prior to the date hereof or accruing during or
related to all periods prior to the date hereof.
3. TNP hereby agrees that it will not require any further consent on
its part to the collateral assignment by Purchaser from time to time
of all of Purchaser's rights, title and interest in and to the Power
Agreement to any lender. Upon foreclosure or sale in lieu of
foreclosure, TNP hereby agrees that TNP will not require any further
consent if the successor or assign by foreclosure or by purchase in
lieu of foreclosure assumes the obligations and liabilities of
purchaser under this Agreement and the Power Agreement, and all
rights under the Power Agreement, subject to the terms and
conditions of the Power Agreement and this Agreement (except the
provisions relating to TNP's consent which is satisfied by this
Agreement), shall inure to the benefit of such Lender or purchaser.
Any such subsequent assignment shall not be a novation.
4. TNP's consent to Purchaser's assignment of the Power Agreement to an
affiliate of Purchaser shall not be withheld if, to TNP's reasonable
satisfaction, (a) the assignee has the operational capability and
financial ability to perform Purchaser's obligations under the Power
Agreement and this Agreement and (b) said assignment will not result
in a change of the legal character or status of the Facility or the
Power Agreement or invalidate or terminate the Power Agreement or
impair TNP's rights under the Power Agreement and this Agreement.
5. TNP hereby confirms that (a) the Power Agreement attached hereto
constitutes the entire agreement of the parties thereto and is a
valid and binding obligation of TNP, enforceable, subject to any
subsequent determination by the Public Utilities Commission of Texas
or any other regulatory authority (all hereinafter referred to as
"Agency"), against TNP by Purchaser in accordance with its terms,
and (b) as of the date of this Agreement, to the best knowledge of
TNP, no party to the Power Agreement is in default thereunder and
there does not exist any event or condition which, with the passage
of time or giving of notice or both, would constitute such a
default.
6. The following statements represent TNP's interpretation of certain
of the contractual obligations under the Power Agreement with
respect to the Facility:
<PAGE> 19
(a) For an initial term ending August 30, 1994, TNP is obligated
to purchase from Purchaser, and Purchaser is obligated to sell
to TNP, that amount of capacity which TNP requires to avoid
purchasing 300 MW of peak capacity. TNP is obligated to
purchase from Purchaser, and Purchaser is obligated to sell to
TNP, the energy associated with the capacity as described in
this subparagraph (a).
(b) If Purchaser exercises its option in a written notice
delivered to TNP by Purchaser no later than August 30, 1991,
in accordance with the Power Agreement, after August 30, 1994,
TNP will be obligated to purchase and Purchaser will be
obligated to sell up to that amount of such capacity referred
to in subparagraph (a) above and associated energy as
described in subparagraph (a), above for such additional term
as may be specified in said notice.
(c) Because the calculation of avoided cost in the Power Agreement
only references the avoided cost of a supplying utility,
capacity supplied TNP by another cogenerator would not reduce
the avoided cost under the Power Agreement.
7. The parties hereto recognize that, pursuant to the Power Agreement
as consistently construed by the parties thereto, TNP is obligated
to pay 98% of the actual avoided cost as provided i the Power
Agreement but only to the extent such payments constitute reasonable
and necessary operating expenses of TNP which are allowed as a
concurrent recovery through the then existing rates of TNP, as
determined by an Agency.
8. The parties will not initiate any action in any judicial or
regulatory proceeding the direct purpose of which is to invalidate
or terminate the Power Agreement or this Agreement except in
accordance with their terms and the parties will not join a third
party in a proceeding before an Agency to invalidate or terminate
the Power Agreement or this Agreement or to determine the payments
by TNP under the Power Agreement not to constitute reasonable and
necessary operating expenses of TNP which are allowed as a
concurrent recovery through the then existing rates of TNP.
9. This Agreement shall be binding upon and inure to the benefit of the
permitted successors and assigns of the parties hereto.
10. CCC hereby transfers and assigns to Purchaser all of CCC's rights,
title and interest in and to the Power Agreement. CCC hereby
represents and warrants that as
<PAGE> 20
of the date hereof the Power Agreement is not pledged, mortgaged, or
otherwise collaterally assigned and the Power Agreement has not been
previously transferred or assigned (other than as collateral) to any
person.
IN WITNESS WHEREOF, the parties have executed this Agreement effective as
of the 3rd day of May, 1988.
CAPITOL COGENERATION COMPANY, LTD.
By its General Partners:
CAPITOL POWER, INC.
By: [SIG]
--------------------------------
Its: President
-------------------------------
BAYPORT COGENERATION, INC.
By: [SIG]
--------------------------------
Its: President
-------------------------------
TEXAS-NEW MEXICO POWER COMPANY
By: /s/ JAMES TARPLEY
-----------------------------------
James Tarpley
Its: President
-----------------------------------
CLEAR LAKE COGENERATION COMPANY, LTD.
By its General Partner:
ENRON COGENERATION THREE COMPANY
By: [SIG]
_______________________________
Its: Senior Vice President
<PAGE> 21
I. SUPPLIER
Clear Lake Cogeneration Limited Partnership
II. AREA SERVED
Texas Gulf Coast (TNP's Southeast Division)
Texas City Point of Delivery with HL&P West Columbia Point of
Delivery with HL&P
III. TERM
Continuing Term - through August 31, 2004.
IV. CONDITIONS OF SALE
Through August 31, 1994
TNP may purchase capacity up to 325 MW in any month, with
Clear Lake committed to making 325 MW available to TNP at all
times. Clear Lake Cogeneration may offer additional capacity
for purchase as it is available. For calendar years 1992 and
1993, TNP must purchase a minimum of 3380 MW annually. For the
period January 1, 1994 to August 31, 1994, T NP must purchase
a minimum of 2253 MW. There is no minimum energy purchase
commitment.
August 31, 1994 through August 31, 2004
TNP may purchase capacity up to 250 MW in any month. Clear
Lake Cogeneration may offer additional capacity for purchase
as it is available. Beginning August 31, 1994, TNP must
purchase a minimum of 2400 MW annually. There is no minimum
purchase commitment.
TNP and Clear Lake Cogeneration have executed a scheduling
agreement, to become effective January 1, 1993, which allows for
100% of all TNP One generated power scheduled for delivery to the
Texas City and West Columbia points of delivery to be credited to
actual loads before purchases from Clear Lake are determined.
Purchases from this supplier are backed up with standby service
purchased from HL&P.
In the event of the complete failure of this supplier to provide
service, TNP has access to a standby pool of 416 MW, in addition to
contractual
November 9, 1992
<PAGE> 22
Clear Lake Cogeneration Limited Partnership - continued
arrangements in place with HL&P for up to 300 MW of firm service
which would replace lost deliveries from Clear Lake.
V. PRICE AND PAYMENT
Demand and energy are priced at 98% of Houston Lighting and Power's
wholesale rate schedule TNP.
Payments to Clear Lake for capacity and energy are determined by the
actual avoidance of purchases which would have otherwise been made
from HL&P.
Under the terms and conditions of the purchase agreements between
TNP and Clear Lake, the payments made by TNP to Clear Lake shall not
exceed in any event the amount of amounts constituting reasonable
and necessary operating expenses of TNP that are allowed as a
recovery through the rates of TNP, as determined by the Public
Utility Commission of Texas.
VI. FUEL SUPPLY
Primary - Natural Gas Standby
Standby - Oil
Clear Lake Cogeneration operates three 100 MW gas turbines and two
steam turbines with a combined output of 75 MW, for a total
dependable capacity of approximately 375 MW.
VII. APPROXIMATE PERCENTAGE OF TEXAS ENERGY REQUIREMENTS SUPPLIED FOR 1991 -
35% (source: 1991 TNP Form 10-K)
<PAGE> 23
[TEXAS-NEW MEXICO POWER COMPANY LETTERHEAD]
May 30, 1990
Mr. David H. Odorizzi
Vice President Corporate Development,
Finance and Treasurer
Enron/Dominion Cogen Corp.
10077 Grogans Mill Road, No. 475
The Woodlands, Texas 77380
Re: No. 89-041946; Clear Lake Cogeneration Limited Partnership v. TNP
Enterprises, Inc., Texas-New Mexico Power Company, Bayport
Cogeneration Inc., Capitol Power, Inc., and Capitol Cogeneration,
Company, Ltd.; In the 269th Judicial District Court of Harris
County, Texas
Dear David:
This Letter Agreement, entered into on the 30th day of May, 1990, between
Clear Lake Cogeneration Limited Partnership ("Clear Lake") and Texas-New Mexico
Power Company ("TNP") (hereinafter, "the Parties") is for the purpose of
settling the claims and controversies between the Parties regarding the
interpretation of (1) the August 31, 1983 Agreement for the Purchase of
Electrical Power and Energy Between Capitol Cogeneration Company, Ltd. and
Texas-New Mexico Power Company (the "Power Agreement") and the Letter Agreement
dated August 14, 1986, between Capitol Power, Inc., Bayport Cogeneration Co.,
Inc. and Texas-New Mexico Power Company (the "August 14, 1986 Letter
Agreement"); and (2) the Agreement Substituting A Party among Capitol
Cogeneration Company, Ltd., Clear Lake Cogeneration Limited Partnership and
Texas-New Mexico Power Company, dated May 3, 1988 (the "Substitution
Agreement"), and made the basis of the lawsuit. In consideration of the mutual
covenants hereinafter set forth and other good and valuable consideration, the
receipt and sufficiency of which are hereby acknowledged, the Parties agree to
the following:
1. Clarification of Article 1 of the Power Agreement. During the term the
Power Agreement is in force and effect, including any renewal and extension
pursuant to the Power Agreement, the Substitution Agreement, the August 14, 1986
Letter Agreement or any other mutual agreement between the parties, "the cost
which TNP
<PAGE> 24
Mr. David H. Odorizzi
May 30, 1990
Page 2
actually avoids from a supplying utility or utilities by purchasing power from
CCC [now Clear Lake] as an alternative to taking the same amount of power supply
from the electric utility or utilities which would otherwise supply the
wholesale power to TNP" shall be deemed to be the Houston Lighting & Power
Company ("HL&P") standard wholesale rate, which is designed to recover HL&P's
fully embedded cost of service, provided that such HL&P standard wholesale rate
for capacity and energy, during the accounting month in which power was sold by
Clear Lake to TNP, was available to TNP under an existing HL&P/TNP power
agreement and tariff in effect and approved by the Texas Public Utility
Commission ("TPUC"). In the event that HL&P is not such a supplier to TNP of
wholesale power at a rate designed to recover HL&P's fully embedded cost of
service, then the "supplying utility" for the purposes of determining "the cost
which TNP actually avoids" shall be determined pursuant to the following
criteria:
(i) the supplying utility's wholesale power rate must be designed to
recover its fully embedded cost of wholesale service;
(ii) the wholesale rate during the accounting month in which power was
sold by Clear Lake to TNP was available to TNP under an existing
power agreement between TNP and the supplying utility and a tariff
in effect and approved by TPUC; and
(iii) Clear Lake power must enable TNP to actually avoid the purchase of
that amount of power of the supplying utility for which Clear Lake
is being paid.
TU Electric Company ("TUEC") shall be deemed to be the initial replacement for
HL&P as the supplying utility for as long as it meets the above criteria. At
such time as TUEC fails to meet the above criteria, then the utility that meets
the above criteria shall be the "supplying utility." TNP represents to Clear
Lake that it has entered into a contract with HL&P for the purchase of wholesale
power at rates designed to recover HL&P's fully embedded cost of providing
wholesale service, with a ten year term from July 13, 1991 through July 12,
2001, subject to approval by the TPUC. The rate for Supplemental KVA found by
the TPUC to be applicable to that contract and tariff will not be include in the
standard wholesale rate used to determine "the cost which TNP actually avoids."
2. Clarification of Article 1 of the Power Agreement, Points 1 and 3 of
the August 14, 1986 Letter Agreement and Paragraph 6(a) of the Substitution
Agreement. Clear Lake shall tender and be compensated for by TNP, and shall
supply if requested by TNP, annual capacity to be no less than 2990 MW for
calendar
<PAGE> 25
Mr. David H. Odorizzi
May 30, 1990
Page 3
years 1990 and 1991. For calendar years 1992 and 1993, Clear Lake shall
tender and be compensated for by TNP, and shall supply if requested by TNP,
annual capacity to be no less than 3380 MW. For the period from January 1, 1994
to August 31, 1994, Clear Lake shall tender and be compensated for by TNP, and
shall supply if requested by TNP, capacity to be no less than 2253 MW. No other
agreement between TNP and other utilities or Qualifying Facilities shall caus
Clear Lake's capacity payments to be reduced under this agreement. In the event
TNP purchases capacity because of Clear Lake's failure to perform and as a
result TNP incurs additional purchased capacity and/or energy expenses, then
Clear Lake shall reimburse TNP for such additional expenses so incurred and
actually paid. TNP has no right to request more than 325 MW, with appropriate
reductions as agreed between the parties for scheduled maintenance. Clear Lake
has the option to supply in excess of 325 MW, if requested by TNP, and if
available from Clear Lake. Clear Lake shall be obligated to use all reasonable
efforts to make 325 MW of capacity available to TNP when such is requested.
3. Clarification of Point 1 of the August 14, 1986 Letter Agreement.
Clear Lake shall reimburse TNP's direct cost for 125 MW of standby capacity,
which amount is adequate to standby clear Lake's single largest generating unit.
Clear Lake shall bear the risk of reduction in payments from TNP to clear Lake
as a result of ratchet charges incurred by TNP for power purchased from a
utility or utilities in the event the 125 MW of standby capacity should not be
sufficient to cover any shortage of power deliveries from Clear Lake to TNP. TNP
agrees to obtain, and clear Lake will pay for, additional capacity through ERCOT
if such is requested by Clear Lake, and if such additional capacity can be
obtained.
4. Clarification of Article 14 of the Power Agreement, Point 3 of the
August 14, 1986 Letter Agreement, and Paragraph 6(b) of the Substitution
Agreement. The Power Agreement and the Substitution Agreement shall be extended
beyond the primary period at the sole option of Clear Lake, for such time as
Clear Lake is able to provide power to TNP. Provided clear Lake gives the
requisite notice to TNP required in Paragraph 6(b) of the Substitution
Agreement, the parties agree that from and after August 31, 1994, Clear Lake
shall tender and be compensated for by TNP, and shall supply if requested by
TNP, annual capacity to be not less than 2400 MW per year on a load profile
similar to that followed in previous years and at the rate determined in
accordance with Paragraph 1 of this Letter Agreement. However, this guaranteed
minimum purchase of 3400 MW per year will not extend beyond August 31, 1997.
5. It is understood and agreed that TNP, to meet its demand, will
schedule Clear Lake capacity subordinate only to TNP One. TNP also agrees to
allow the existing contractual arrangement between TNP and the Texas Municipal
Power Authority ("TMPA") to expire and
<PAGE> 26
Mr. David H. Odorizzi
May 30, 1990
Page 4
that TNP will allow Clear Lake the opportunity to service such energy and
capacity previously served by TMPA. TNP will not execute any new supply
agreements for supply to TNP's Southeast Division before January 1, 1992 for
supply after August 31, 1994 without first providing Clear Lake the opportunity
to enter into a contract on equivalent terms for said supply.
6. The provisions of the Power Agreement and Substitution Agreement, as
hereby clarified, are ratified and confirmed and shall remain in full force and
effect, including, but not limited to the provision that, notwithstanding the
provisions of this Letter Agreement, the payments made by TNP to Clear Lake
shall not exceed in any event the amount or amounts constituting reasonable and
necessary operating expenses of TNP that are allowed as a recovery through the
rates of TNP, as determined by the Texas Public Utility Commission.
No party to this Letter Agreement shall release any information to a third
party without the agreement of the other party concerning this settlement, its
terms and conditions, or the fact that it has occurred, except (1) as expressly
required by law including, but not limited to, applicable security laws and
regulations or regulatory authorities or as a party may deem in good faith to be
required for governmental reporting purposes; (2) as ordered by a regulatory
agency or a court of competent jurisdiction; (3) to prospective lenders and
financial consultants; and (4) as expressly agreed to in advance in writing by
the other party to this Letter Agreement.
This Letter Agreement shall be effective from the date of execution
forward, and shall be binding upon and inure to the benefit of the successors
and assignees of the Parties.
Texas-New Mexico Power Company
By: /s/ J. V. Chambers
------------------------------------
J. V. Chambers
Sector Vice President
Revenue Production
AGREED:
Enron/Dominion Cogen Corp. on its own
behalf and on behalf of its affiliates
and subsidiaries.
By: /s/ DAVID H. ODORIZZI
-------------------------------------
David H. Odorizzi
Vice President Corporate Development,
Finance and Treasurer
<PAGE> 27
August 28, 1991
Mr. J. V. Chambers
Sector Vice President,
Revenue Production
Texas-New Mexico Power Company
4100 International Plaza
Fort Worth, Texas 76113
Re: August 31, 1983 Agreement for the Purchase of Electrical Power and
Energy Between Clear Lake Cogeneration, Limited Partnership and
Texas-New Mexico Power Company (the "Power Agreement"), as Clarified
by Letter Agreements Dated August 14, 1986, May 3, 1988 and May 30,
1990
Dear Jack:
This Letter Agreement, entered into and effective as of the 28th day of August,
1991, between Clear Lake Cogeneration, Limited Partnership ("Clear Lake") and
Texas-New Mexico Power Company ("TNP") is to memorialize an agreement that Clear
Lake and TNP have reached regarding Clear Lake's option to extend the Power
Agreement beyond its primary term.
Article 14 of the Power Agreement states that the agreement shall extend for a
primary term of eleven years from the date thereof (the "Primary Term"). By
letter agreement dated August 14, 1986, Capitol Cogeneration Company Limited
("CCC") (Clear Lake's predecessor in interest), by and through its partners,
Capitol Power, Inc. and Bayport Cogeneration Co., Inc. and TNP clarified certain
terms of the Power Agreement. Among other things, Point 3 of the Letter
Agreement states that for capacity that the seller (now Clear Lake) wishes to
sell to TNP after the expiration of the Primary Term of the Power Agreement, the
parties will enter into a written agreement regarding the sale of such capacity
"no later than (3) three years before the end of the [P]rimary [T]erm" (the
"Option Date").
<PAGE> 28
Mr. J. V. Chambers
August 28, 1991
Page 2
Paragraph 6(b) of the May 3, 1988 Agreement Substituting a Party between CCC,
Clear Lake and TNP (the "Substitution Agreement") states that if Clear Lake
desires to exercise its option to extend the Power Agreement, it must deliver
TNP written notice of its intent no later than August 30, 1991.
In a letter agreement dated May 30, 1990 between Clear Lake and TNP, which was
executed for the purpose of settling claims and controversies between Clear Lake
and TNP regarding the interpretation of the Power Agreement and the
aforementioned letter agreements, Clear Lake and TNP further defined TNP's
purchase obligations beyond the Primary Term of the agreement in the event Clear
Lake, at its sole option, gives TNP the notice described in Paragraph 6(b) of
the Substitution Agreement.
Recently, Clear Lake and TNP agreed that it would be to the mutual benefit of
both parties to change the Option Date to two years before the end of the
Primary Term. To clarify Article 14 of the Power Agreement, Point 3 of the
August 14, 1986 Letter Agreement, Paragraph 6(b) of the May 3, 1988 Substitution
Agreement and Paragraph 4 of the May 30, 1990 Letter Agreement, and in
consideration of the mutual benefits that will result to the parties by
extending Clear Lake's Option Date, Clear Lake and TNP agree to the following:
the Power Agreement and the Substitution Agreement shall be extended beyond the
Primary Term at the sole option of Clear Lake, and under the terms and
conditions set forth in Paragraph 4 of the May 30, 1990 Letter Agreement,
provided that Clear Lake gives TNP written notice no later than August 30, 1992.
This Letter Agreement shall be binding upon and inure to the benefit of the
successors and assignees of the parties.
Enron/Dominion Cogen Corp., on
its own behalf and on behalf of
its affiliates and subsidiaries
By: /s/ DAVID W. SHIELDS
------------------------------------
David W. Shields
Vice President and
Chief Financial Officer
<PAGE> 29
Mr. J. V. Chambers
August 28, 1991
Page 3
AGREED:
Texas-New Mexico Power Company
By: /s/ J. V. CHAMBERS
-----------------------------
J. V. Chambers
Sector Vice President
Revenue Production
<PAGE> 30
[TEXAS-NEW MEXICO POWER COMPANY LETTERHEAD]
August 31, 1992
Mr. DeWayne Roberts
Vice President, Operations
Enron Power Corp.
P. O. Box 1188
Houston, Texas 77251-1188
Dear De Wayne:
Pursuant to our conversation today, TNP and Clear Lake (the "Parties")
agree and recognize that TNP is in receipt of a binding extension of the Power
Agreement pursuant to paragraph 6(b) of the Substitution Agreement dated May 3,
1988, as amended by the Letter Agreement dated August 28, 1991. It is hereby
agreed by both parties that it is the intent that TNP One - Units 1 and 2 will
be baseload units (Unit 1 = 146 MW x 8760 hrs. x 87.5% CF and Unit 2 = 151.6 MW
x 8760 hrs. x 87.5% CF) in TNP's daily and annual resource schedules. In order
to accomplish said baseload operation and to increase the efficiency of the TNP
One and Clear Lake Cogen generation facilities, it is hereby agreed that the
parties will enter into detailed negotiations to be completed by September 15,
1992. The purpose of the negotiations will be the development of written
procedures to define daily and annual scheduling methodologies and practices to
accomplish the intent of the Parties. Such methodology and practices to be
reduced to a letter agreement between the Parties. However, the terms and
conditions of the intended letter agreement, nor any language contained herein,
shall affect the August 31, 1992 extension of the Power Agreement.
It is recognized that Clear Lake desires to have annually defined and
guaranteed purchase minimums in the amount of 2400 MW/yr. In order for TNP to
accommodate Clear Lake's desire to sell such annual capacity, the
afore-referenced scheduling practices and procedures are necessary. The
afore-referenced practices and procedures will require a written agreement
similar to the attached sample which attempts to describe the intent of the
Parties. The attached is not binding on either of the Parties but used for
illustrative purposes only.
TEXAS-NEW MEXICO POWER COMPANY
By: /s/ J. V. CHAMBERS
-----------------------------
J. V. Chambers
Sector Vice President
Revenue Production
AGREED AND ACCEPTED
By: /s/ DEWAYNE W. ROBERTS
--------------------------
DeWayne W. Roberts
ENRON DOMINION COGEN CORP.
On Its Behalf and the Behalf of Its
Affiliates and Subsidiaries
<PAGE> 31
[CLEAR LAKE LETTERHEAD]
August 31, 1992
Mr. J. V. Chambers
Sector Vice President,
Revenue Production
Texas-New Mexico Power Company
4100 International Plaza
Fort Worth, Texas 76113
Re: August 31, 1983 Agreement for the Purchase of Electrical Power and
Energy Between Clear Lake Cogeneration, Limited Partnership and
Texas-New Mexico Power Company (the "Power Agreement"), as Clarified
by Letter Agreements dated August 14, 1986, May 3, 1988, May 30,
1990 and August 28, 1991
Dear Jack:
This Letter Agreement, entered into as of the 31st day of August, 1992,
between Clear Lake Cogeneration, Limited Partnership ("Clear Lake") and
Texas-New Mexico Power Company ("TNP") and effective as of August 31, 1994, is
to affirm the August 31, 1983 Agreement for the Purchase of Electrical Power and
Energy between Capitol Cogeneration Company, Ltd. and Texas-New Mexico Power
Company, as clarified by Letter Agreement dated August 14, 1986, Agreement
Substituting a Party dated May 3, 1988, Letter Agreement dated May 30, 1990 and
Letter Agreement dated August 28, 1991, altogether known and considered as the
"Power Agreement" and to extend the terms thereof through August 30, 2004.
Pursuant to Paragraph 6(b) of the May 3, 1988 Agreement Substituting a
Party, as amended by the Letter Agreement dated August 28, 1991, Clear Lake
hereby gives TNP notice of the extension of the Power Agreement through August
30, 2004, upon the terms and conditions set forth therein as clarified from time
to time.
<PAGE> 32
Mr. J. V. Chambers
August 31, 1992
Page 2
In consideration of the mutual covenants set forth within the Power
Agreement, and other good and valuable consideration to be received thereunder,
the parties hereto agree to the following:
1. The extension of the Power Agreement by Clear Lake is appropriate
under the terms of such Power Agreement and the term of the
extension shall be from August 31, 1994, through August 30, 2004.
2. The terms and conditions of the Power Agreement shall remain in full
force and effect for the term of the extension except for such
conditions that by their own language expire. The parties hereto
agree that the term "Qualifying Facilities" as used in the Power
Agreement shall be deemed to include other suppliers of wholesale
electric capacity and associated energy (e.g., independent power
producers, exempt wholesale generators, etc.).
3. Pursuant to Exhibit A of the Power Agreement and by Point 1 of the
May 30, 1990 Letter Agreement clarifying the Power Agreement, Clear
Lake shall tender and be compensated for by TNP, and shall supply if
requested by TNP, annual capacity on a load profile similar to that
followed in previous years. This annual capacity and energy
scheduling of TNP's resources for the term of this extension will be
addressed in a separate agreement to be completed by September 15,
1992.
4. TNP hereby releases the right to request in excess of 250 MW of
instantaneous capacity. Clear Lake shall use all reasonable efforts
to make 250 MW of capacity available to TNP if such is requested.
Clear Lake has the option, but not the obligation, to supply in
excess of 250 MW, if requested by TNP and if available from Clear
Lake. Compensation for all capacity and energy supplied by Clear
Lake in excess of the 250 MW limit shall be paid to clear Lake by
TNP pursuant to Exhibit A of the Power Agreement and by Point 1 of
the May 30, 1990 Letter Agreement clarifying the Power Agreement.
<PAGE> 33
Mr. J. V. Chambers
August 31, 1992
Page 3
5. The parties agree to cooperate in reasonable efforts to reduce the
cost of standby capacity provided for Clear Lake.
6. TNP will not enter into any new agreements for supply to TNP's
Southeast Division before August 31, 2002, for delivery after August
31, 2004, without first providing Clear Lake the opportunity to
enter into a contract on equivalent terms for said supply.
Enron/Dominion Cogen Corp., on its
own behalf and on behalf of its
affiliates and subsidiaries
By: /s/ DEWAYNE W. ROBERTS
------------------------------------
DeWayne W. Roberts
Vice President, Operations
AGREED:
Texas-New Mexico Power Company,
on its own behalf and on behalf of
its affiliates and subsidiaries
By: /s/ J. V. CHAMBERS
-----------------------------
J. V. Chambers
Sector Vice President
Revenue Production
<PAGE> 34
[TEXAS-NEW MEXICO POWER COMPANY LETTERHEAD]
September 15, 1992
Mr. DeWayne Roberts
Vice President, Operations
Enron Power Corp.
333 Clay St.
3 Allen Center - Room 400
Houston, Texas 77002
Dear Mr. Roberts:
Enclosed please find one executed original of the Scheduling Agreement.
Sincerely yours,
/s/ EDDIE HALE
Eddie Hale
Supervisor - Contracts
EH:lm
Enclosure
<PAGE> 35
[TEXAS-NEW MEXICO POWER COMPANY LETTERHEAD]
September 15, 1992
Mr. DeWayne W. Roberts
Vice President, Operations
ENRON POWER CORP.
P. O. Box 1188
Houston, Texas 77251-1188
Re: Notice of Extension, Dated August 31, 1992, to Extend the Terms of the
August 31, 1983 Agreement for the Purchase of electrical Power and Energy
Between Clear Lake Cogeneration, Limited Partnership and Texas-New Mexico
Power Company as Clarified by Letter Agreements Dated August 14, 1986, May
3, 1988, May 30, 1990, and August 28, 1991 (altogether, the "Power
Agreement")
Dear DeWayne:
Pursuant to Paragraph 3 of the Notice of Extension dated August 31, 1992,
and in recognition of the Letter of Intent dated August 31, 1992 (Attachment A),
this Scheduling Agreement, entered into as of the 15th day of September, 1992,
between Clear Lake Cogeneration, Limited Partnership ("Clear Lake"), and
Texas-New Mexico Power Company ("TNP") (hereinafter, "the Parties") is to
clarify the following: 1) the annual capacity which Clear Lake shall tender and
be compensated for by TNP, and shall supply if requested by TNP; and 2) the
methodologies employed by the Parties to schedule the generation of the TNP One
and Clear Lake facilities, and to enhance the efficient use of the generation
facilities of both Clear Lake and TNP. In recognition of the foregoing, the
Parties agree to the following:
1. TNP shall schedule power from Clear Lake as needed to meet forecasted
hourly loads at TNP's West Columbia and Bacliff points of delivery ("PODs") with
Houston Lighting & Power ("HL&P") not met by power scheduled from TNP One. In
determining the amount of power to be scheduled hourly from Clear Lake, TNP may
include an amount of Clear Lake power to assist in meeting unanticipated load
increases at the two PODs. This amount of Clear Lake power may crate some
quantity of TNP One power which is not credited to actual load.
2. The Parties recognize that the resource scheduling methodology described
above in Paragraph 1 may increase the amount of TNP One energy which will not be
credited to
<PAGE> 36
September 14, 1992
Mr. DeWayne Roberts
Enron Power Corp.
Page 2
actual loads when calculated strictly in accordance with Schedule 3
of the Agreement for Utility Services between TNP and HL&P. In consideration for
scheduling of resources as described above in Paragraph 1, the calculation of
the amount of energy purchased by TNP from Clear Lake shall incorporate the
amount of any energy generated at TNP One and scheduled for delivery at TNP's
West Columbia and Bacliff PODs with HL&P, which will include any TNP One energy
not credited to actual loads by HL&P at the West Columbia and Bacliff PODs due
to the sum of all scheduled resources exceeding actual loads at the PODs. The
amount of TNP One energy not credited by HL&P but incorporated in the
calculation of purchases of energy from Clear Lake shall be limited in
accordance with Paragraph 3 below.
3. Annual Allowable Energy Exceptions for TNP One, for use in calculating
energy purchases by TNP from Clear Lake shall be determined as described below:
a) For the purposes of this Scheduling Agreement, the term "Annual
Allowable Energy Exceptions" shall be defined as the maximum
quantity of TNP One energy, projected on an annual basis as
described below in points 3b and 3c, which may be used in addition
to the amount of energy generated at TNP One, scheduled and actually
delivered at TNP's West Columbia and Bacliff PODs with HL&P.
b) From the effective date of this Scheduling Agreement to January 1,
1995, Annual Allowable Energy Exceptions for TNP One shall be
156,103,200 KWH per year, which is the difference between annual
baseload operation at TNP One and the defined minimum annual energy
production at TNP One, as calculated and shown in Attachment B.
c) From and after January 1, 1995, Annual Allowable Energy Exceptions
for TNP One shall be 195,523,200 KWH, which is the difference
between annual baseload operation at TNP One and the defined minimum
annual energy production at TNP One, as calculated and shown in
Attachment B.
4. The quantities of TNP One energy used in calculating monthly energy
purchases from Clear Lake shall be determined by TNP from monthly billing data
received from HL&P. The Parties understand and agree that the monthly billing
data prepared by HL&P and provided to TNP contains an interval by interval
calculation of TNP One "exceptions" for both the West Columbia and Bacliff PODS.
The Parties further understand and agree that the "exceptions" represent the
quantity of TNP One power which was generated, scheduled for delivery, and
delivered to the respective POD, but not actually credited to load at the POD
due to the sum of all scheduled resources exceeding actual load at the POD.
<PAGE> 37
September 14, 1992
Mr. DeWayne Roberts
Enron Power Corp.
Page 3
TNP shall, on a monthly basis, include as TNP One energy actual power
generated at TNP One which is scheduled for delivery at TNP's West Columbia and
Bacliff PODs with HL&P, which will include any TNP One energy which is
identified in the billing data received from HL&P, as TNP One "exceptions" as
defined within this Paragraph 4. TNP One "exceptions" which occur during "Period
1 hours" shall not be included in the calculation of total TNP One energy to be
credited to total TNP load at TNP's West Columbia and Bacliff PODs as described
in this Paragraph 4. "Period 1 hours" shall be defined as follows: 1) for the
months of June to September, hour-ending 0100 to hour ending 0700; and 2) for
all remaining months, hour-ending 2400 to hour-ending 0500. If, at any time
during a given calendar year, the cumulative total of actual monthly TNP One
"exceptions" used in the determination of total TNP One energy to be credited to
TNP's PODs exceeds the annual allowable Energy Exceptions as defined above in
Paragraph 3, for the balance of that calendar year any further TNP One
"exceptions" identified in billing data received from HL&P shall not be used in
the determination of total TNP One energy to be credited to TNP's PODs.
Total TNP One energy, as described in the preceding paragraph, including
any applicable TNP One "exceptions" as defined previously shall be credited
against total metered load at TNP's West Columbia and Bacliff PODs as provided
in the monthly HL&P billing data for each POD. The residual load remaining after
the crediting of TNP One power as described above shall be used in the
determination of the "S(1)" component of the "S(1) - S(2)" billing formula. TNP
shall provide Clear Lake with sufficient documentation to verify the calculation
of TNP One energy quantities as described in this Scheduling Agreement. Further,
TNP shall provide Clear Lake with copies of monthly capacity factor information
as reported to the Public Utility Commission of Texas.
5. In recognition of the terms and conditions of this Scheduling Agreement,
and pursuant to Exhibit A to the Power Agreement, and Paragraph 3 of the Notice
of Extension, from August 31, 1994, Clear Lake shall tender and be compensated
for by TNP, and shall supply if requested by TNP, annual capacity of no less tan
2400 MVA, on a load profile similar to that followed in previous years.
6. The term of this Scheduling Agreement shall be from January 1, 1993 to
August 31, 2004.
7. The Parties acknowledge that forecasting daily and monthly loads entails
the prediction of local weather patterns, load patterns, etc., and therefore the
results of scheduling resources in the manner described above in Paragraph 1
cannot be quantified and guaranteed by either Party. Further, the Parties
recognize that nothing contained in this Scheduling Agreement shall prevent or
limit TNP's ability to schedule its available resources
<PAGE> 38
September 14, 1992
Mr. DeWayne Roberts
Enron Power Corp.
Page 4
to provide least cost electric service to its retail customers.
8. The Parties recognize that the determination of Annual Allowable Energy
Exceptions as presented in Attachment B reflect the contracted wheeling
quantities for TNP One generation at the time of execution of this Scheduling
Agreement. Following the execution of this Scheduling Agreement, Attachment B
shall be amended as necessary to reflect the then-current quantities of TNP One
generation available for schedule and delivery to TNP's West Columbia and
Bacliff PODs with HL&P.
9. The Parties agree that this Scheduling Agreement shall be amended as
necessary to reflect any amendments, or revisions which may be made to Schedule
3 of the Agreement for Utility Services between TNP and HL&P to affect the order
in which scheduled resources are applied by HL&P to actual load. Such amendments
to this Scheduling Agreement shall be completed within thirty (30) days of the
effective date of the amendment or revision to Schedule 3.
Texas-New Mexico Power Company,
on its own behalf and on behalf of
its affiliates and subsidiaries
By: /s/ J. V. CHAMBERS
------------------------------
J. V. Chambers
Sector Vice President -
Revenue Production
Agreed and Accepted:
Enron/Dominion Cogen Corp.
on its own behalf and on behalf of
its affiliates and subsidiaries
By: /s/ DEWAYNE W. ROBERTS
----------------------------
DeWayne W. Roberts
Vice President, Operations
<PAGE> 39
ATTACHMENT A
<PAGE> 40
[TEXAS-NEW MEXICO POWER COMPANY LETTERHEAD]
August 31, 1992
Mr. DeWayne Roberts
Vice President, Operations
Enron Power Corp.
P. O. Box 1188
Houston, Texas 77251-1188
Dear DeWayne:
Pursuant to our conversation today, TNP and Clear Lake (the "Parties")
agree and recognize that TNP is in receipt of a binding extension of the Power
Agreement pursuant to paragraph 6(b) of the Substitution Agreement dated May 3,
1988, as amended by the Letter Agreement dated August 28, 1991. It is hereby
agreed by both parties that it is the intent that TNP One - Units 1 and 2 will
be baseload units (Unit 1 = 146 MW x 8760 hrs. x 87.5% CF and Unit 2 = 151.6 MW
x 8760 hrs. x 87.5% CF) in TNP's daily and annual resource schedules. In order
to accomplish said baseload operation and to increase the efficiency of the TNP
One and Clear Lake Cogen generation facilities, it is hereby agreed that the
parties will enter into detailed negotiations to be completed by September 15,
1992. The purpose of the negotiations will be the development of written
procedures to define daily and annual scheduling methodologies and practices to
accomplish the intent of the Parties. Such methodology and practices to be
reduced to a letter agreement between the Parties. However, the terms and
conditions of the intended letter agreement, nor any language contained herein,
shall affect the August 31, 1992 extension of the Power Agreement.
It is recognized that Clear Lake desires to have annually defined and
guaranteed purchase minimums in the amount of 2400 MW/yr. In order for TNP to
accommodate Clear Lake's desire to sell such annual capacity, the
afore-referenced scheduling practices and procedures are necessary. The
afore-referenced practices and procedures will require a written agreement
similar to the attached sample which attempts to describe the intent of the
Parties. The attached is not binding on either of the Parties but used for
illustrative purposes only.
TEXAS-NEW MEXICO POWER COMPANY
By: /s/ J. V. CHAMBERS
------------------------------------
J. V. Chambers
Sector Vice President
Revenue Production
AGREED AND ACCEPTED
By: /s/ DEWAYNE W. ROBERTS
----------------------------
DeWayne W. Roberts
ENRON DOMINION COGEN CORP.
On Its Behalf and the Behalf of Its
Affiliates and Subsidiaries
<PAGE> 41
ATTACHMENT B
<PAGE> 42
DETERMINATION OF ANNUAL ALLOWABLE ENERGY EXCEPTIONS
<TABLE>
<S> <C>
a) From the effective date of this Scheduling Agreement to January 1, 1995,
annual baseload operation of TNP One, Units 1 and 2, for purposes of this
Scheduling Agreement, shall be defined as follows:
Unit 1 Net Output = 146,000 KW
Unit 2 Net Output = 151,600 KW
Schedule to TUEC = 60,000 KW
Annual Target Capacity Factor = 87.5 %
1. Target Annual Baseload KWH:
((146,000 KW + 151,600 KW) - 60,000 KW) x 8760 Hrs. x 87.5 % CF = 1,821,204,000 KWH
2. Defined Minimum Annual Energy Production (based on 80 % target CF):
((146,000 KW + 151,600 KW) - 60,000 KW) x 8760 Hrs. x 80.0 % CF = 1,665,100,800 KWH
3. Annual Allowable Energy Exceptions:
Target annual baseload operation (line 1) = 1,821,204,000 KWH
Minimum Annual Energy Production (line 2) = 1,665,100,800 KWH
Annual Allowable Energy Exceptions = 156,103,200 KWH
b) From and after January 1, 1995, annual baseload operation of TNP One,
Units 1 and 2, for purposes of this Scheduling Agreement, shall be defined
as follows:
Unit 1 Net Output = 146,000 KW
Unit 2 Net Output = 151,600 KW
Schedule to TUEC = 0 KW
Annual Target Capacity Factor = 87.5 %
4. Target Annual Baseload KWH:
(146,000 KW + 151,600 KW) x 8760 Hrs. x 87.5 % CF = 2,281,104,000 KWH
5. Defined Minimum Annual Energy Production (based on 80 % target CF):
(146,000 KW + 151,600 KW) x 8760 Hrs. x 80.0 % CF = 2,085,580,800 KWH
6. Annual Allowable Energy Exceptions:
Target annual baseload operation (line 4) = 2,281,104,000 KWH
Minimum Annual Energy Production (line 5) = 2,085,580,800 KWH
Annual Allowable Energy Exceptions = 195,523,200 KWH
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
The Schedule contains summary financial information extracted from
Calpine Corporation's Consolidated Balance Sheet as of December 31, 1997
and from the Consolidated Statement of Operations for the twelve months
ended December 31, 1997 and is qualified in its entirety by reference
to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 48,513
<SECURITIES> 0
<RECEIVABLES> 42,805
<ALLOWANCES> 0
<INVENTORY> 6,015
<CURRENT-ASSETS> 166,578
<PP&E> 868,111
<DEPRECIATION> 148,390
<TOTAL-ASSETS> 1,380,956
<CURRENT-LIABILITIES> 178,586
<BONDS> 742,934
0
0
<COMMON> 20
<OTHER-SE> 239,936
<TOTAL-LIABILITY-AND-EQUITY> 1,380,956
<SALES> 237,277
<TOTAL-REVENUES> 276,321
<CGS> 144,701
<TOTAL-COSTS> 153,308
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 61,466
<INCOME-PRETAX> 53,159
<INCOME-TAX> 18,460
<INCOME-CONTINUING> 34,699
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 34,699
<EPS-PRIMARY> 1.74
<EPS-DILUTED> 1.65
</TABLE>
