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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 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
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, $0.01 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 21, 1997: $367.6 million
Common stock outstanding as of March 21, 1997: 19,869,219
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 1997 Annual
Meeting of Shareholders:....................................................
Part III (Items 10, 11, 12 and 13)
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CALPINE CORPORATION
FORM 10-K
ANNUAL REPORT
FOR THE YEAR ENDED DECEMBER 31, 1996
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
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<S> <C> <C>
PART I
ITEM 1. Business................................................................ 1
ITEM 2. Properties.............................................................. 33
ITEM 3. Legal Proceedings....................................................... 34
ITEM 4. Submission of Matters To A Vote of Security Holders..................... 34
PART II
ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters... 34
ITEM 6. Selected Financial Data................................................. 34
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results 34
of Operations...........................................................
ITEM 8. Financial Statements and Supplementary Data............................. 34
ITEM 9. Changes In and Disagreements with Accountants and Financial 34
Disclosure..............................................................
PART III
ITEM 10. Executive Officers, Directors and Key Employees......................... 35
ITEM 11. Executive Compensation.................................................. 35
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.......... 35
ITEM 13. Certain Relationships and Related Transactions.......................... 35
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......... 36
Signatures.......................................................................... 43
Index to Consolidated Financial Statements and Schedules............................ F-1
Schedule 11 Calculation of Earnings Per Share
Exhibit Index
</TABLE>
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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. 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 risks
and uncertainties 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, and (iii) 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 and its subsidiaries (the "Company" or "Calpine") is
engaged in the acquisition, development, 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 interests in 15 power
generation facilities and steam fields having an aggregate capacity of 1,047
megawatts. Since its inception in 1984, Calpine has developed substantial
expertise in all aspects of electric power generation. The Company's vertical
integration has resulted in significant growth over the last five years as
Calpine has applied its extensive engineering, construction management,
operations, fuel management and financing capabilities to successfully implement
its acquisition and development program. During the last five years, Calpine has
expanded substantially, from $55.4 million of total assets as of December 31,
1992 to $1.0 billion of total assets as of December 31, 1996. Calpine's revenue
for 1996 increased to $214.6 million, representing a compound annual growth rate
of 52.6% since 1992. The Company's EBITDA for 1996 increased to $117.4 million
(see Item 6. Selected Financial Data). Calpine's strategy is to capitalize on
opportunities in the power market through an ongoing program to acquire,
develop, own and operate electric generation facilities, as well as marketing
power and energy services to utilities and other end users.
STRATEGY
Calpine's objective is to become a leading power company by capitalizing on
emerging market opportunities in the domestic and international 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 Calpine believes provides it
with a competitive advantage. By pursuing this strategy, the Company has
significantly expanded and diversified its project portfolio. Since 1993, the
Company has completed transactions involving five gas-fired cogeneration
facilities and two steam fields. As a result of these transactions, the Company
has more than doubled its aggregate power generation capacity and substantially
diversified its fuel mix.
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, rather than exclusively
through long-term power sales agreements. As part of Calpine's initial effort to
develop merchant plants, the Company entered into an agreement with Phillips
Petroleum Company to develop a gas-fired cogeneration project with a capacity of
240 megawatts. Under this agreement, approximately 90 megawatts of electricity
will be sold to the Phillips Houston Chemical Complex, with the remainder to be
sold into the competitive market through
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Calpine's power marketing activities. The Company expects that this project will
represent a prototype for future merchant plant developments. The development of
this project is subject to the satisfaction of various conditions including
required approvals. See "Development and Future Projects."
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 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.
Continue to develop an integrated power marketing capability. The Company
is developing an integrated power marketing capability, conducted through its
wholly owned subsidiary, Calpine Power Services Company ("CPSC"). In 1995, CPSC
received approval from the Federal Energy Regulatory Commission ("FERC") to
conduct power marketing activities. The Company believes that a power marketing
capability complements its business strategy of providing low cost power
generation services. CPSC's power marketing activities will focus on the
development of long-term customer service relationships, supported primarily by
generating assets that are owned, operated or controlled by Calpine. CPSC will
aggregate the Company's own resources, the resources of its customers, power
pool resources, and market power supply to provide the customized services
demanded by its customers at a competitive price.
Selectively expand into international markets. Internationally, the
Company intends to utilize its geothermal and gas-fired expertise in selected
markets of Southeast Asia and Latin America, where demand for power is rapidly
growing and private investment is encouraged. In November 1995, the Company made
a loan to Coperlasa, which operates the Cerro Prieto Steam Fields located in
Baja California, Mexico. In March 1996, the Company entered into a joint venture
agreement to pursue the development of a geothermal resource in Indonesia with
an estimated potential capacity in excess of 500 megawatts. Calpine believes
that its investments in these projects will effectively position it for future
expansion in Southeast Asia and Latin America.
DESCRIPTION OF POWER PLANTS
The Company has interests in 15 power generation facilities and steam
fields with a current aggregate capacity of approximately 1,047 megawatts,
consisting of seven natural gas-fired cogeneration power plants with a total
capacity of 522 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 458 megawatts. Each of the power generation
facilities produces electricity for sale to a utility. 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 natural 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 all
power generation facilities in which the Company has an interest, except for the
Thermal Power Company Steam Fields and the Cerro Prieto Steam Fields. 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
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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
debt for the project.
In order to provide fuel for the gas-fired power generation projects 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
structures 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
projects. 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. See
Item 2. Properties.
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 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 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. See
"Governmental Regulation."
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The table below sets forth certain information regarding the Company's
power generation facilities and steam fields currently in operation.
POWER GENERATION FACILITIES
<TABLE>
<CAPTION>
COMMENCEMENT TERM OF
POWER NAMEPLATE CALPINE CALPINE NET OF POWER
GENERATION CAPACITY INTEREST INTEREST COMMERCIAL UTILITY SALES
POWER PLANT TECHNOLOGY (MEGAWATTS)(1) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER AGREEMENT
- --------------- ------------- -------------- ------------ ----------- ------------ -------------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Sumas Gas-Fired Puget Sound
Cogeneration 125 75%(2) 93.8 1993 Power & Light 2013
King City Gas-Fired Pacific Gas &
Cogeneration 120 100% 120 1989 Electric 2019
Gilroy Gas-Fired Pacific Gas &
Cogeneration 120 100% 120 1988 Electric 2018
Greenleaf 1 Gas-Fired Pacific Gas &
Cogeneration 49.5 100% 49.5 1989 Electric 2019
Greenleaf 2 Gas-Fired Pacific Gas &
Cogeneration 49.5 100% 49.5 1989 Electric 2019
Agnews Gas-Fired Pacific Gas &
Cogeneration 29 20% 5.8 1990 Electric 2021
Watsonville Gas-Fired Pacific Gas &
Cogeneration 28.5 100% 28.5 1990 Electric 2009
West Ford Flat Geothermal Pacific Gas &
27 100% 27 1988 Electric 2008
Bear Canyon Geothermal Pacific Gas &
20 100% 20 1988 Electric 2008
Aidlin Geothermal Pacific Gas &
20 5% 1 1989 Electric 2009
</TABLE>
STEAM FIELDS
<TABLE>
<CAPTION>
COMMENCEMENT
APPROXIMATE CALPINE CALPINE NET OF
CAPACITY INTEREST INTEREST COMMERCIAL UTILITY ESTIMATED
STEAM FIELD (MEGAWATTS)(3) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER LIFE(4)
- ----------- -------------- ------------ ----------- ------------ --------------------- ---------
<S> <C> <C> <C> <C> <C> <C>
Thermal 151 100% 151 1960 Pacific Gas & 2018
Power Electric
Company
PG&E Unit 86 100% 86 1980 Pacific Gas & 2018
13 Electric
PG&E Unit 82 100% 82 1985 Pacific Gas & 2018
16 Electric
SMUDGEO #1 59 100% 59 1983 Sacramento Municipal 2018
Utility District
Cerro 80 100%(5) 80 1973 Comision Federal 2000(6)
Prieto de Electricidad
</TABLE>
- ---------------
(1) Nameplate capacity may not represent the actual output for a facility at any
particular time.
(2) See "Power Generation Facilities -- Sumas Power Plant" for a description of
the Company's interest in the Sumas partnership and current sales of power
by the Sumas Power Plant.
(3) Capacity is expected to gradually diminish as the production of the related
steam fields declines. See "Steam Fields."
(4) Other than for the Cerro Prieto Steam Fields, 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. See "Steam Fields."
(5) 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
Fields.
(6) Represents the actual termination of the steam sales agreement. See "Steam
Fields -- Cerro Prieto Steam Fields."
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Power Generation Facilities
Sumas Power Plant
The Sumas cogeneration facility (the "Sumas Power Plant") is a 125 megawatt
natural gas-fired, combined cycle 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. The
Company currently holds a 50% interest in Sumas and SEI holds the other 50%
interest. At the time the Company receives a 24.5% pre-tax rate of return on its
partnership investment in Sumas, the Company's interest will be reduced to
11.33% and SEI's interest will increase to 88.67%. Further, the Company receives
an additional 25% of the cash flow of the Sumas Power Plant to repay principal
and interest on $11.5 million of loans to the sole shareholder of SEI. A $1.5
million loan bears interest at 20% and matures in 2003 and a $10.0 million loan
bears interest at 16.25% and matures in 2004. 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 comprised of an MS 7001EA combined cycle gas turbine manufactured by
General Electric Company ("General Electric"), 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%.
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. 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 London Interbank
Offered Rate ("LIBOR"), which are amortized over a 15-year period ending in
2008.
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>
1997......... 3.38c 2003......... 6.22c 2009......... 5.40c
1998......... 3.64c 2004......... 6.33c 2010......... 5.49c
1999......... 3.98c 2005......... 6.45c 2011......... 5.58c
2000......... 4.23c 2006......... 6.57c 2012......... 5.58c
2001......... 6.23c 2007......... 5.23c 2013......... 5.58c
2002......... 6.11c 2008......... 5.31c
</TABLE>
The variable price component is set according to a scheduled rate set forth
in the agreement, which in 1996 was 0.99c per kilowatt hour, and escalates
annually by a factor equal to the U.S. Gross National Product Implicit Price
Deflator. For 1996, the average price paid by Puget under the power sales
agreement was 4.166c 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
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shared with the Sumas Power Plant. In 1996, the Sumas Power Plant's net profit
increased by $501,000 as a result of the displacement provision.
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 pounds 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
qualified facility ("QF") status. See "Government Regulation."
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 130 billion cubic feet as of January 1, 1997.
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 million British thermal units per day ("mmbtu/day") to the
Sumas Power Plant. The remaining 12,100 mmbtu/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.
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 1996, the Sumas Power Plant generated approximately 1,032,000,000
kilowatt hours of electrical energy and approximately $44.0 million of total
revenue. In 1996, the Company recognized income of approximately $6.4 million in
accordance with the terms of the Sumas partnership agreement, and recorded
revenue of $2.0 million for services performed under the operating and
maintenance agreement.
King City Power Plant
The King City cogeneration power plant (the "King City Power Plant") is a
120 megawatt natural 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/Eriksen 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 and
has operated at an average availability of approximately 99%.
Electricity generated by the King City Power Plant is sold to Pacific Gas
and Electric Company ("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. As-delivered capacity prices are $188 per kilowatt year for 1997 and
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.
Through 1998, payments for electrical energy produced are based on 100% of
PG&E's avoided cost of energy for the period of January 1 through April 30, and
80% at avoided cost and 20% at fixed prices for the period of May 1 through
December 31. The fixed average energy price in effect for 1997 and 1998 under
the
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King City power sales agreement is 13.14c per kilowatt hour. Thereafter, PG&E is
required to pay for electrical energy actually delivered at prices equal to
PG&E's then avoided cost of energy (as determined by the California Public
Utilities Commission ("CPUC")). PG&E's avoided cost of energy varies from month
to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt
hour since 1992. During 1996, PG&E's avoided cost of energy averaged
approximately 2.26c 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. See
"Government Regulation." 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 pursuant to a
contract with Chevron U.S.A. Inc. ("Chevron"), expiring June 30, 1997. Natural
gas is transported under a firm transportation agreement, expiring June 30,
1997, via a dedicated 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 1996, the King City Power Plant generated approximately 411,977,000
kilowatt hours of electrical energy and approximately $41.5 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.
The acquisition of the Gilroy Power Plant was originally financed utilizing
a non-recourse project loan 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 (see Note 18 of the Notes to Consolidated Financial Statements).
The power plant consists of a General Electric Frame 7 Model EA combustion
turbine generator, an AEG-KANIS (ABB) 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 power plant has
operated at an average availability of 94%.
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 $188 per kilowatt year for 1997. 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 electrical energy actually delivered during
the
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<PAGE> 10
period of dispatchable operation at a price equal to PG&E's avoided cost of
energy excluding adders. Thereafter, during the period of baseload operation,
PG&E is required to pay for electrical energy actually delivered at prices equal
to PG&E's then avoided cost of energy. PG&E's avoided cost of energy has varied
from month to month and has ranged from an annual average of 1.84c to 2.96c per
kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged
approximately 2.26c 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 with 1995 revenues of approximately $24.1 billion. It is necessary
to continue to operate the host facility in order to maintain the Gilroy Power
Plant's QF status. See "Government Regulation."
Natural gas for the Gilroy Power Plant is supplied pursuant to a contract
with Amoco Energy Trading Corporation ("Amoco") expiring July 31, 1997. Natural
gas is transported under a firm transportation agreement, expiring July 1, 1997.
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.
From August 29, 1996 through December 31, 1996, the Gilroy Power Plant
generated approximately 231,365,000 kilowatt hours of electrical energy for sale
to PG&E and approximately $14.7 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 Greenleaf 1 and 2 Power Plants have a combined natural gas requirement
of approximately 22,000 mmbtu/day. The Company, through its wholly owned
subsidiary Calpine Fuels Corporation ("Calpine Fuels"), entered into a gas
supply agreement with Montis Niger, Inc. ("MNI"), an affiliate of LFC, which
owns and operates a local gas field connected to the facilities. On January 31,
1997, the Company purchased the stock of MNI. Calpine Fuels supplements the MNI
gas supply with a short-term contract with Coastal Gas Marketing Company, which
expires on April 30, 1997. This gas is delivered over PG&E's intrastate pipeline
which is directly connected to each facility. The Greenleaf 1 and 2 Power Plants
have interruptible transportation agreements with PG&E, expiring in June 1997.
Greenleaf 1 Power Plant. The Greenleaf 1 cogeneration facility (the
"Greenleaf 1 Power Plant") is a 49.5 megawatt natural 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 power plant has operated at an
average availability of approximately 92.5%.
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
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<PAGE> 11
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 1997. 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 a price equal to
PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost
of energy varies from month to month and has ranged from an annual average of
1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of
energy averaged approximately 2.26c 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 1996, the Greenleaf 1 Power Plant did not
experience curtailment. PG&E may also interrupt or reduce deliveries if
necessary to repair its system or because of system emergencies, forced outages,
force majeure and compliance with prudent electrical practices.
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. See "Government Regulation."
The Greenleaf 1 Power Plant is located on 77 acres owned by the Company
near Yuba City, California.
For 1996, the Greenleaf 1 Power Plant generated approximately 354,182,000
kilowatt hours of electrical energy for sale to PG&E and approximately $18.1
million in revenue.
Greenleaf 2 Power Plant. The Greenleaf 2 cogeneration facility (the
"Greenleaf 2 Power Plant") is a 49.5 megawatt natural 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 power plant has operated at an average availability of approximately 96%.
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 1997. 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 a
price equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's
avoided cost of energy varies from month to month and has ranged from an annual
average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's
avoided cost of energy averaged approximately 2.26c 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 1996, the Greenleaf 2 Power Plant did not
experience curtailment. PG&E may also interrupt or reduce deliveries if
necessary to repair its system or because of system emergencies, forced outages,
force majeure and compliance with prudent electrical practices.
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. See "Government
Regulation."
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.
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<PAGE> 12
For 1996, the Greenleaf 2 Power Plant generated approximately 399,707,000
kilowatt hours of electrical energy for sale to PG&E and approximately $19.3
million in revenue.
Agnews Power Plant
The Agnews cogeneration facility (the "Agnews Power Plant") is a 29
megawatt natural 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%.
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, 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 1997 and 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, PG&E's avoided cost of energy (as determined by the CPUC).
PG&E's avoided cost of energy varies from month to month and has ranged from an
annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996,
PG&E's avoided cost of energy averaged approximately 2.26c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased
under the power sales agreement by 995 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 (which has historically been less
than one megawatt per year) 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. See "Government
Regulation."
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<PAGE> 13
The supply of natural gas for the Agnews Power Plant is currently provided
under a full requirements fuel supply agreement between O.L.S. Energy-Agnews and
Amoco Energy Trading Corporation ("Amoco") which expires June 30, 1997.
Intrastate transportation is provided under a firm gas transportation agreement
with PG&E, expiring in June 1997.
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 had an initial term of six years, expiring on
December 31, 1996, and was renewed for an additional six-year term effective
January 1, 1997.
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 1996, the Agnews Power Plant generated approximately 205,838,000
kilowatt hours of electrical energy and total revenue of $11.0 million. In 1996,
the Company recognized a loss of approximately $190,000 as a result of the
Company's 20% ownership interest and recorded revenue of $2.0 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 natural gas-fired, combined cycle 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 power
plant has operated at an average availability of approximately 97%.
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 the fixed energy price schedule set forth
below, and 99% of the energy will be sold at PG&E's avoided cost of energy. The
following schedule sets forth the fixed average energy prices (expressed in
cents per kilowatt hour) and the as-delivered capacity prices per kilowatt year
through 2000 for energy deliveries under the Watsonville Power Plant power sales
agreement:
<TABLE>
<CAPTION>
ENERGY AS-DELIVERED
YEAR PRICE CAPACITY PRICE
--------------------------------------------------- ------ --------------
<S> <C> <C>
1997............................................... 13.14c $188
1998............................................... 13.90c $188
1999............................................... 13.90c $188
2000............................................... 13.90c $188
</TABLE>
Thereafter, PG&E will pay for energy delivered at prices equal to PG&E's
avoided cost of energy (as determined by the CPUC), 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. PG&E's avoided cost of energy varies from
month to month and has ranged from an annual average of 1.84c to 2.96c per
kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged
approximately 2.26c per kilowatt hour.
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<PAGE> 14
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 October 1 though April 30. From January 1, 1996 through December 31, 1996,
PG&E curtailed energy purchases of 1,290 hours under the power sales agreement.
In addition to the sale of electricity to PG&E, during 1996 the Watsonville
Power Plant produced and sold steam to two thermal hosts, Norcal Frozen Foods,
Inc. ("Norcal") and Farmers Processing, both food processors. In August 1995,
Norcal sold its facility to a subsidiary of Dean Foods ("Dean Foods"), which
closed the facility on February 9, 1996. The lessor of the Watsonville Power
Plant has constructed a water distillation facility on the site of the
Watsonville Power Plant to replace the Dean Foods food processing facility. This
facility commenced operations in August 1996 and is operated by the Company. It
is necessary to continue to operate the host facilities in order to maintain the
Watsonville Power Plant's QF status. See "Government Regulation."
Amoco is the supplier of natural gas to the Watsonville Power Plant. The
Company has negotiated a contract with Amoco which will be effective through
June 30, 1997. The Company's current contract is on a month-to-month basis with
Amoco. PG&E provides firm gas transportation to the Watsonville Power Plant
under a contract expiring June 30, 1997.
The Watsonville Power Plant is located on 1.8 acres of land leased from
Dean Foods under the terms of a 30-year lease expiring in 2010.
For 1996, the Watsonville Power Plant generated approximately 205,942,000
kilowatt hours of electrical energy for sale to PG&E and approximately $10.6
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.,
and seven production wells and 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%.
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 1997 and 1998 is 13.83c cents
per kilowatt hour under the West Ford Flat power sales agreement. Thereafter,
PG&E is required to pay for electrical energy actually delivered at prices equal
to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided
cost of energy varies from month to month and has ranged from an annual average
of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost
of energy averaged approximately 2.26c per kilowatt hour. The Company cannot
accurately predict the avoided cost of energy prices that will be in effect at
the expiration of the fixed price period under this agreement.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased
under this agreement by 1,000 hours. In the event of such curtailment, the
Company's results of operations may be materially adversely affected. The
Company currently expects the maximum amount of curtailment allowed under the
agreement during 1997.
The Company believes that the geothermal reserves that supply energy for
use by the West Ford Flat Power Plant will be sufficient to operate at full
capacity for the entire term of the power sales agreement due
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<PAGE> 15
principally to high reservoir pressures, 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. For a description of the leases covering the properties
located in The Geysers, see Item 2. Properties.
During 1996, the West Ford Flat Power Plant generated approximately
219,849,000 kilowatt hours of electrical energy for sale to PG&E and
approximately $31.9 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%.
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 and
as-delivered capacity prices through 1998 are 13.83c per kilowatt hour and $188
per kilowatt year, respectively. Thereafter, PG&E will pay for energy delivered
at prices equal to PG&E's avoided cost of energy (as determined by the CPUC),
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. PG&E's avoided cost of energy
varies from month to month and has ranged from an annual average of 1.84c to
2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy
averaged approximately 2.26c per kilowatt hour. The Company cannot accurately
predict the avoided cost of energy prices that will be in effect at the
expiration of the fixed price period under this agreement.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased
under this agreement by 1,000 hours. In the event of any such curtailment, the
Company's results of operations may be materially adversely affected. The
Company currently expects the maximum amount of curtailment allowed under the
agreement during 1997.
The Company believes that the geothermal reserves for the Bear Canyon Power
Plant will be sufficient to operate at full capacity for substantially all of
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. For a description of the leases covering the
properties located at The Geysers, see Item 2. Properties.
During 1996, the Bear Canyon Power Plant generated approximately
161,785,000 kilowatt hours of electrical energy and approximately $22.8 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
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<PAGE> 16
interest is held in the form of a 10% general partnership interest in a limited
partnership (the "Aidlin 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 99%.
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 prices equal to PG&E's avoided cost of energy (as
determined by the CPUC). PG&E's avoided cost of energy varies from month to
month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour
since 1992. During 1996, PG&E's avoided cost of energy averaged approximately
2.26c per kilowatt hour. The Company cannot accurately predict the avoided cost
of energy that will be in effect at the expiration of the fixed price period
under this agreement.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased
under this agreement by 1,000 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 1996, the Aidlin Power Plant generated approximately 167,804,000
kilowatt hours of electrical energy and revenue of $22.3 million. In 1996, the
Company recognized revenue of approximately $331,000 as a result of the
Company's 5% ownership interest and $4.0 million for services performed under
the operating and maintenance agreement.
Steam Fields
Thermal Power Company Steam Fields
The Company acquired Thermal Power Company on September 9, 1994 for a
purchase price of $66.5 million. Thermal Power Company 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") owns 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 over 240 production
wells, 18 injection wells and 55 miles of steam-transporting pipeline. See Item
2. Properties. The 12 plants have a nameplate capacity of 978 megawatts and
currently have the capability to operate at over 600 megawatts. The steam fields
commenced commercial operation in 1960.
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<PAGE> 17
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. 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 1996
was 1.622c per kilowatt hour. The price for 1997 is expected to be approximately
1.907c per kilowatt hour. In addition, the Company receives a monthly fee for
effluent disposal and maintenance. During 1996, such monthly fee was $147,000
per month.
In March 1996, the Company 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 the Company and Union Oil with the intent
that it be at competitive market prices. The Company 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. Under the steam sales
agreement, the Company is required to pay PG&E for the unamortized costs,
including site clean-up, removal and abandonment costs, of power plants that are
installed but are unused as a result of steam supply deficiency. 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, the Company makes offset payments at a reduced rate until total
offsets calculated since July 1, 1991 equal $15.0 million. Accordingly, the
Company's share of offsets in 1996 was $672,000. In approximately 2000 or 2001,
when total offsets may exceed $15.0 million, in accordance with the agreement
the Company'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).
In accordance with the steam sales agreement, PG&E may curtail the power
plants which receive steam in order to produce energy from lower cost sources.
PG&E is contractually 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. During 1996, the Thermal Power Company Steam Fields
experienced curtailment of steam production due to low gas prices and abundant
hydro power. The Company receives a monthly fee for PG&E's right to curtail its
power plants. Such fee was $13,200 per month during 1996.
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, the Company 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, the Company may terminate the agreement with a two-year written
notice to PG&E. If the Company 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, the Company 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. The
Company 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 nameplate
capacity. This percentage reflects a decline in productivity since the
commencement of operations. While it is not possible to accurately predict
long-term
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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
was approximately 9% until 1995, during which year extensive curtailment
interrupted the decline trend. The Company expects steam field productivity to
continue to decline in the future. The Company plans to work with Union Oil and
PG&E to partially offset the expected rate of decline by the development of
water injection projects and power plant improvements.
During 1996, the PG&E power plants produced 3,208,984,000 kilowatt hours of
electrical energy of which the Company's 25% share is 802,246,000 kilowatt hours
for approximately $13.1 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. See Item 2. Properties. Unit 13 and Unit 16
have nameplate capacities of 98 and 113 megawatts, respectively, and currently
operate at outputs of approximately 86 and 82 megawatts, respectively. The PG&E
Unit 13 Steam Field includes 956 acres, 30 production wells, three 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, one
injection well, 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 1996 was 0.955c per kilowatt
hour. The price for 1997 is expected to be approximately 0.985c 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 63,000,000 kilowatt hours under
the steam sales agreement during 1996.
The steam sales agreement with PG&E continues in effect for as long as
either Unit 13 or Unit 16 remains in commercial operation, which depends 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. The Company currently estimates that the productive capacity of the
PG&E Unit 13 and Unit 16 Steam Fields is approximately 22 years. However, no
assurance can be given that the operation of either Unit 13 or Unit 16 will not
become economically impractical at any time during these periods.
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 approximately $10.0 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 80% 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 8.7% in 1996. 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.
During 1996, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient
steam to permit Unit 13 and Unit 16 to produce approximately 1,269,400,000
kilowatt hours of electrical energy and approximately $12.8 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"). See Item 2.
Properties. The SMUD power plant has a nameplate capacity of 72 megawatts and
currently operates at an output of 59 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 $1.77 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. Based on current
estimates and analyses performed by the Company, the Company does not expect
SMUD to suspend payments for steam under this provision. 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 82% of its nameplate capacity. This
percentage reflects a decline in the productivity of the SMUDGEO #1 Steam Fields
since commencement of operations. Although the SMUDGEO #1 Steam Fields
productivity increased in 1995 and did not decline in 1996 (due to curtailment
of neighboring plants), the Company expects the SMUDGEO #1 Steam Fields'
productivity to decline in the future.
During 1996, the SMUDGEO #1 Steam Fields produced approximately 6,835,390
thousand pounds of steam and approximately $14.6 million of revenue.
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
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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 (see Note 8 of the
Notes to Consolidated Financial Statements).
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.
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 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. While the
Company believes that Coperlasa is in an advantageous position to renegotiate or
bid for the right to supply steam over a longer term, there can be no assurance
that the steam sales agreement will be extended beyond its current termination
date.
DEVELOPMENT AND FUTURE PROJECTS
The Company is continually engaged in the evaluation of various
opportunities for the development and acquisition of additional power generation
facilities. However, there is no assurance the Company will be successful in the
acquisition or development of power generation projects in the future. See "Risk
Factors."
Pasadena Cogeneration Project
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 Cogeneration Project"). 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 marketing activities. The Company provided a $3.0 million letter of credit
to Phillips to secure the performance under the Energy Project Development
Agreement. On December 20, 1996, the Company entered into a credit agreement
with ING U.S. Capital Corporation to provide $98.6 million of non-recourse
project financing for the Pasadena Cogeneration Project. In accordance with the
terms of the agreement, Calpine Corporation, through its wholly owned
subsidiaries, Calpine Pasadena Cogeneration, Inc. and Calpine Texas
Cogeneration, Inc., contributed $53.1 million in equity to the project. The
Company commenced construction in February 1997, with commercial operation
scheduled to begin in October 1998. However, there can be no assurances that the
Company will be successful in completing any additional power sales agreements
or that the anticipated schedule for construction will be met.
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Glass Mountain Geothermal Project
Calpine is pursuing the development of a geothermal power project at Glass
Mountain, which is located in northern California about 25 miles south of the
Oregon border (the "Glass Mountain Project"). Glass Mountain is believed to be
the largest undeveloped geothermal resource in the United States. In area, the
resource is larger than The Geysers, where approximately 1,200 megawatts of
capacity is operating. The Company believes that Glass Mountain has an estimated
potential in excess of 1,000 megawatts and is seeking potential customers for
the power to be produced by this project.
In August 1994, the Company entered into a partnership with Trans-Pacific
Geothermal Corporation ("TGC") to construct and operate a 30 megawatt project at
Glass Mountain (the "Partnership"). TGC had previously signed a memorandum of
understanding ("MOU") with Bonneville Power Administration ("BPA") and the
Springfield, Oregon Utility Board ("SUB") to develop the project at Vale,
Oregon. BPA and SUB consented on August 25, 1994 to the assignment of the MOU to
the Partnership and the relocation of the project to Glass Mountain. The MOU
contemplated execution of a 45-year power purchase agreement subject to
satisfaction of certain conditions precedent and included an option for an
additional 100 megawatts.
In December 1996, the Partnership and BPA entered into a settlement
agreement which restructured the rights and obligations of the parties. In
return for a $12.0 million payment by BPA to the Partnership and the grant by
the Partnership to BPA of future options to purchase power at Glass Mountain,
the Partnership and BPA terminated the MOU and certain ancillary agreements. In
addition, BPA will pay the Partnership additional consideration should certain
future events occur related to ongoing environmental review of the Glass
Mountain project. Following the settlement with BPA, TGC withdrew from the
Partnership (see Note 7 of the Notes to Consolidated Financial Statements).
In March 1996, the Company completed the acquisition of certain Glass
Mountain geothermal leases. As a result, the Company currently holds an interest
in approximately 29,000 acres of federal geothermal leases at Glass Mountain.
See Item 2. Properties.
Indonesian Geothermal Project
Calpine plans to develop geothermal facilities in the Lampung Province of
Indonesia, located in southern Sumatra. The geothermal resource at Ulubelu is
estimated to have potential capacity in excess of 500 megawatts. The Company
anticipates that the facility would sell electricity to Perusahaan Umum Listrik
Negara ("PLN"), the state-owned electric company. The first phase of the project
is expected to be 110 megawatts.
The Company's joint venture partner will be PT. Dharmasatrya Arthasentosa
("DATRA"), a company with interests in coal mining and other ventures. The
Company expects that it will be the project's managing partner, with
responsibility for the design, construction and operation of the power plant.
The ownership structure, as planned, will be a joint venture with DATRA in which
the Company would be the managing partner and hold at least a 50% equity
interest, and as much as 85% of the project. DATRA would hold up to 50% of the
project.
In March 1996, the Company and DATRA entered into a joint venture agreement
to develop Ulubelu. The Company and DATRA are negotiating with the National
Resource Agency Pertamina ("Pertamina") regarding resource development. Deep
test well drilling and flow tests by Pertamina are planned during 1997 at
Ulubelu. Commercial operation is anticipated in 2001 for the initial phase of
the project. There can be no assurances, however, that this transaction will be
consummated on these terms, if at all, that the proposed timetable will be met
or that commercial operation of these resources will be feasible.
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
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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 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
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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 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. See "Public Utility Holding Company Regulation."
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
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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 seven natural
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 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 contract becomes a part of a utility's cost structure
(generally reflected in its retail rates), power sales contracts 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 contracts. 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,
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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 by January 1, 1988. 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 January 1, 1998 restructure implementation goal.
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 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, eligibility and phase-in schedule for customer choice (direct
access), the continuation of public purpose programs and issues related to
issuance of rate reduction bonds.
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 restructur-
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ing 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.
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 material 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
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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 material 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
material 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 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.
COMPETITION
The Company competes with independent power producers, including affiliates
of utilities, in obtaining long-term agreements to sell electric power to
utilities. In addition, utilities may elect to expand or create generating
capacity through their own direct investments in new plants. Over the past
decade, obtaining a power sales agreement with a utility has become an
increasingly more difficult, expensive and competitive process. In the past few
years, more contracts have been awarded through some form of competitive
bidding. Increased competition also has lowered profit margins of successful
projects. The Company believes that the power marketing business represents an
opportunity to take advantage of growing competition in the electric power
industry. The Company also believes that the power marketing business will be
highly competitive.
The demand for power in the United States traditionally has been met by
utilities constructing large-scale electric generating plants under rate-based
regulation. The enactment of PURPA in 1978 spawned the growth of the independent
power industry, which expanded rapidly in the 1980s. The initial independent
power producers were an entrepreneurial group of cogenerators and small power
producers who recognized the potential business opportunities offered by PURPA.
This initial group of independents was later joined by larger, better
capitalized companies, such as subsidiaries of fuel supply companies,
engineering companies, equipment manufacturers and affiliates of other
industrial companies. In addition, a number of regulated utilities have created
subsidiaries (known as utility affiliates) that compete with independent power
producers. Some independent power producers specialize in market "niches," such
as a specific technology or fuel (e.g., gas-fired cogeneration, geothermal,
hydroelectric, refuse-to-energy, wind, solar, coal and wood), or a specific
region of the country where they believe they have a market advantage. The
Company presently conducts its operations primarily in the United States and
concentrates on gas-fired and geothermal cogeneration plants.
The Company is the second largest producer of geothermal energy in the
United States. Although the Company is an established leader in the geothermal
power industry and has been rapidly growing, most of the Company's competitors
have significantly greater capital, financial and operational resources.
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Recent amendments to PUHCA made by the Energy Policy Act of 1992 are likely
to increase the number of competitors in the independent power industry by
reducing certain restrictions currently applicable to certain projects that are
not QFs under PURPA. However, the recent amendments also should make it simpler
for the Company to develop new projects itself, for example, by enabling the
Company to develop large, gas-fired generation projects without the necessity of
locating its projects in the vicinity of a steam host or otherwise finding a
steam host to accept the useful thermal output required of a cogeneration
facility under PURPA.
EMPLOYEES
As of December 31, 1996, the Company employed 254 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.
RISK FACTORS
High Leverage
The Company is highly 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, 1996, the Company's total consolidated
indebtedness was $601.1 million, its total consolidated assets were $1.0 billion
and its stockholders' equity was $203.1 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.
The Indenture dated as of May 16, 1996 (the "10 1/2% Indenture") relating
to the 10 1/2% Senior Notes Due 2006 and the Indenture dated as of February 17,
1994 (the "9 1/4% Indenture") relating to the Company's 9 1/4% Senior Notes Due
2004 (the "9 1/4% Senior Notes") (collectively, the "Indentures" and the "Senior
Notes") contain certain restrictive covenants. Such restrictions affect, and in
many respects significantly limit or prohibit, among other things, the ability
of the Company or its subsidiaries or such other entities, as the case may be,
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 Indentures also contain
provisions that require the Company, in the event of a Change of Control
Triggering Event (as such term is defined in the Indentures), to make an offer
to purchase the Senior Notes. There can be no assurance that the Company will
have the financial resources necessary to purchase the Senior Notes upon a
Change of Control (as such term is defined in the Indentures). Such Change of
Control provisions contained in the Indentures may not be waived by the Board of
Directors of the Company.
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 Senior Notes, and to enable the
Company to comply with the terms of its 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 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 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.
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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 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. In addition, there can be no assurance that all required
governmental permits and approvals for the Company's new or acquired facilities
will be obtained, that the Company will be able to obtain favorable power sales
agreements and adequate financing, or that the Company will be successful in the
development of power generation facilities in the future. Historically, the
Company has been successful in obtaining debt financing for its facilities and
had relied on Electrowatt Ltd. ("Electrowatt"), formerly the Company's sole
stockholder, to provide funding for a substantial portion of its facility equity
commitments. Over the past few years, the Company has maintained a $50.0 million
credit facility with Credit Suisse (the "Credit Suisse Credit Facility"), which
was arranged for the Company by Electrowatt. In connection with the Company's
initial public offering of Common Stock in September 1996 (the "Common Stock
Offering"), Electrowatt sold all of its shares of Common Stock of the Company
and, as a result, the Company will no longer be able to rely on Electrowatt for
financing. Upon the completion of the Common Stock Offering, the Credit Suisse
Credit Facility was terminated.
On September 25, 1996, the Company entered into a $50.0 million three-year
revolving credit facility with The Bank of Nova Scotia (the "Bank of Nova Scotia
Credit Facility"). The Bank of Nova Scotia 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's power generation facilities have been financed using a
variety of leveraged financing structures, primarily consisting of non-recourse
debt and lease obligations. As of December 31, 1996, the Company had
approximately $601.1 million of total consolidated indebtedness, of which
approximately 51% represented non-recourse subsidiary debt. Each non-recourse
debt and lease 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 significant 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
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
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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. If the lenders or lessors were
to require such guarantees, and the Company were unable to incur indebtedness in
respect of such guarantees under the restrictions on indebtedness (including
guarantees) contained in the Indentures, the Company's ability to fund new
facilities could be adversely affected. The Indentures do not limit the ability
of the Company's subsidiaries to incur non-recourse or lease financing for
investment in new facilities.
Calpine Geysers Company, L.P. ("CGC"), a wholly owned subsidiary of
Calpine, owns the West Ford Flat Power Plant, the Bear Canyon Power Plant, the
PG&E Unit 13 and Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields. Calpine
Greenleaf Corporation ("Calpine Greenleaf"), a wholly owned subsidiary of
Calpine, owns the Greenleaf 1 and 2 Power Plants. The non-recourse facility
financing of each of CGC and Calpine Greenleaf is collateralized by all of the
assets and properties of each of the facilities and steam fields owned by such
subsidiary. In the event of a reduction in revenue derived from one or more of
these facilities or steam fields which results in a failure to make any payments
on, or if such subsidiary otherwise defaults in its obligations under the terms
of, its non-recourse project financing, the lenders would be entitled to
foreclose on all of the assets of such subsidiary, including the assets
pertaining to each such facility and 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.
Impact of Avoided Cost Pricing; Energy Price Fluctuations
Nine of the existing power plants in which the Company has an interest sell
electricity to PG&E under separate long-term power sales agreements. Each of
these agreements provides for both capacity payments and energy payments for the
term of the agreement. During the initial ten-year period of certain of the
agreements, PG&E pays a fixed price for each unit of electrical energy according
to schedules set forth in such agreements. The fixed price periods under these
power sales agreements expire at various times in 1998 through 2000. 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 PG&E's then prevailing avoided cost of energy, which is
determined and published from time to time by the CPUC. The term "avoided cost"
refers to the incremental costs that an electric utility would incur to produce
or purchase an amount of power equivalent to that purchased from qualifying
facilities (as defined under PURPA). The
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currently prevailing avoided cost of energy is substantially lower than the
fixed energy prices under these power sales agreements and is generally expected
to remain so. While avoided cost does not affect capacity payments under the
power sales agreements, in the event that the avoided cost of energy does not
increase significantly, the Company's energy revenue under these power sales
agreements would be materially reduced at the expiration of the fixed price
period. Such reduction could have a material adverse effect on the Company's
results of operations. The Company cannot accurately predict the likely level of
avoided cost energy prices at the expiration of the fixed price periods. 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.
Impact of Curtailment
Each of the Company's power and steam sales agreements contains curtailment
provisions pursuant to which the purchasers of energy or steam are entitled to
reduce the number of hours of energy or amount of steam purchased thereunder.
Curtailment provisions are customary in power and steam sales agreements. During
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 higher levels of energy
generation by hydroelectric power facilities that supply electricity. In limited
circumstances, energy production from third party geothermal power plants may be
curtailed, which would reduce deliveries of steam by the Company under the steam
sales agreements. The Company expects maximum curtailment during 1997 under its
power sales agreements for certain of its facilities, and there can be no
assurance that the Company will not experience curtailment in the future. In the
event of such curtailment, the Company's results of operations may be materially
adversely affected.
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 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.
The Company has grown substantially in recent years as a result of
acquisitions of interests in power generation facilities and steam fields such
as the Transactions. 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.
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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 all of the power generation facilities and
steam fields in which it has an interest, except for two steam fields. 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 in excess of 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 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.
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 1996, approximately 86% and 7% of
the Company's total revenue was attributable to revenue received pursuant to
power and steam sales agreements with PG&E and Sacramento Municipal Utility
District ("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. During 1996, an additional 4% of the Company's revenue was
attributable to operating and maintenance services performed by the Company for
power generation facilities that sell electricity to PG&E.
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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.
International Investments
The Company has made an investment in the Cerro Prieto geothermal steam
fields located in Mexico and intends to pursue investments primarily in Latin
America and Southeast Asia. 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.
Power Marketing Business
It is part of the Company's strategy to continue to develop an integrated
nationwide power marketing business to market power generated both by the
Company's generation facilities and power generated by third parties. However,
the power marketing industry is only in its early stages of development, and
there are no assurances that the industry will develop in such a way as to
permit the Company to achieve these goals. Furthermore, the Company has only
recently commenced its power marketing business, and there can be no assurance
that its power marketing strategy will be successful or that the Company's goals
will be achieved.
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
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<PAGE> 34
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.
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. 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 net revenues.
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<PAGE> 35
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 new power sales agreements, and this competition has
contributed to a reduction in electricity prices. In this regard, many utilities
often engage in "competitive bid" solicitations to satisfy new capacity demands.
This competition adversely affects the ability of the Company to obtain power
sales agreements and the price paid for electricity. There also is increasing
competition between electric utilities, particularly in California where the
CPUC and the California legislature have launched an initiative designed to give
all electric consumers the ability to choose between competing suppliers of
electricity. 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.
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, 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.
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 also maintains a regional
office in Santa Rosa, California under a lease that expires in 1999.
The Company, through its ownership of CGC and Thermal Power Company, 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 and Thermal Power
Company's 25% undivided interest in the Thermal Power Company Steam Fields which
are operated by Union Oil. The Company has subleasehold interests in three
leases comprising 6,825 acres of federal geothermal resource lands in the Coso
area in central California. 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
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<PAGE> 36
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.
See "Item 1. Business -- Description of Facilities" for a description of
the other material properties leased or owned by the projects in which the
Company has ownership interests. The Company believes that its properties are
adequate for its current operations.
ITEM 3. LEGAL PROCEEDINGS
The Company, together with over 100 other parties, was named as a defendant
in an action brought in August 1993 by the bankruptcy trustee for Bonneville
Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the Chapter 11
Trustee for Bonneville Pacific Corporation v. Portland General Corporation, et
al., in the United States District Court for the District of Utah (the "Court").
In December 1996, the trustee and the Company entered into a settlement
agreement relating to this matter. The trustee has agreed to waive all claims
against the Company and to dismiss the trustee's litigation against the Company
in exchange for a payment of $767,500 by the Company.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. Management does not expect that the
outcome of these cases will have a material adverse effect on the Company's
financial position or results of operations.
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. Calpine Corporation 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.
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ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES
Incorporated by reference from Proxy Statement relating to the 1997 Annual
Meeting of Shareholders.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Proxy Statement relating to the 1997 Annual
Meeting of Shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Proxy Statement relating to the 1997 Annual
Meeting of Shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CS Holding, a Swiss corporation, holds approximately 44.9% of the
outstanding shares of Electrowatt, which, prior to the Common Stock Offering,
held all of the outstanding capital stock of the Company. CS Holding also holds
(i) approximately 100% of the outstanding shares of Credit Suisse and (ii)
approximately 69.3% of the outstanding common stock of CS First Boston, Inc.,
which holds all of the outstanding common stock of CS First Boston Corporation.
CS First Boston Corporation was one of the underwriters of the Company's 9 1/4%
Senior Notes issued in February 1994 and was one of the placement agents in the
sale of the 10 1/2% Senior Notes Due 2006. CS First Boston was also an
underwriter in the Common Stock Offering.
In January 1990, O.L.S. Energy-Agnews entered into a credit agreement with
Credit Suisse providing for a $28 million loan to finance the construction of
the Agnews Power Plant. The Company holds a 20% interest in O.L.S.
Energy-Agnews. The loan is collateralized by all of the assets of the Agnews
Power Plant and bears interest on the unpaid principal balance based on LIBOR
plus a margin rate varying between .50% and 1.50%. After commencement of
commercial operation, the Agnews Power Plant was sold to Nynex Credit
Corporation under a sale leaseback arrangement with O.L.S. Energy-Agnews and
Credit Suisse. Under the sale leaseback, O.L.S. Energy-Agnews entered into a
22-year lease, commencing February 1991, providing for the payment of a fixed
base rental, as well as renewal options and a purchase option at the termination
of the lease. As of December 31, 1995, O.L.S. Energy-Agnews's outstanding
obligation of its sale leaseback arrangement was $37.6 million.
In September 1990, the Company obtained a $25.3 million Credit Facility
from Credit Suisse. In April 1993, the Credit Suisse Credit Facility was amended
to increase the amount of credit available to the Company to $54.0 million. The
Credit Suisse Credit Facility was unsecured and bore interest on the amounts
outstanding from time to time, if any, at LIBOR plus .50% per annum. During
1994, the Company completed a $105.0 million public debt offering of the 9 1/4%
Senior Notes. A portion of the net proceeds were used to repay $52.6 million
indebtedness outstanding under the Credit Suisse Credit Facility. On April 21,
1995, the Company entered into the Credit Suisse Credit Facility providing for
advances of $50.0 million. On April 29, 1996, the amount of advances available
under the Credit Suisse Credit Facility was increased to $58.0 million. A
portion of the proceeds of the sale of the 9 1/4% Senior Notes Due 2004 was used
to repay outstanding borrowings under the Credit Suisse Credit Facility of
approximately $53.7 million on May 16, 1996. The amount of advances available
under the Credit Suisse Credit Facility was subsequently restored to $50.0
million. Upon completion of the Common Stock Offering, the Credit Suisse Credit
Facility was terminated.
In January 1992, Sumas and its wholly owned subsidiary, ENCO, entered into
loan agreements with Prudential and Credit Suisse providing for a $120.0 million
loan to finance the construction of the Sumas Power Plant and acquisition of
associated gas reserves. See "Item 1. Business -- Description of Facilities --
Power Generation Facilities -- Sumas Cogeneration Power Plant." As of December
31, 1996, the outstanding indebtedness of Sumas and ENCO under the term loan was
$117.0 million.
In December 1994, the Company entered into a Consulting Agreement with Mr.
George Stathakis, a Director, which was amended and restated effective June 3,
1996. See the Proxy Statement relating to the 1997 Annual Meeting of
Shareholders.
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In January 1995, the Company and Electrowatt entered into a management
services agreement, which replaced a prior similar agreement, under which
Electrowatt agreed to provide the Company with advisory services in connection
with the construction, financing, acquisition and development of power projects,
as well as any other advisory services as may be required by the company in
connection with the operation of the Company. The Company had agreed to pay
Electrowatt $200,000 per year for all services rendered under the management
services agreement. Pursuant to this agreement, $166,000 and $200,000 were paid
in 1996 and 1995, respectively. Upon completion of the Common Stock Offering,
the management services agreement was terminated.
In 1995, the Company paid $106,000 to Electrowatt pursuant to a guarantee
fee agreement whereby Electrowatt agreed to guarantee the payment when due of
any and all indebtedness of the Company to Credit Suisse in accordance with the
terms and conditions of the Credit Suisse Credit Facility. Under the guarantee
fee agreement, the Company had agreed to pay to Electrowatt an annual fee equal
to 1% of the average outstanding balance of the Company's indebtedness to Credit
Suisse during each quarter as compensation for all services rendered under the
guarantee fee agreement. Upon completion of the Common Stock Offering, the
guarantee fee agreement was terminated.
In June 1995, Calpine repaid $57.5 million of non-recourse financing to
Credit Suisse which was outstanding indebtedness related to the Greenleaf 1 and
2 Power Plants at the time of the acquisition of such facilities.
In March 1996, Electrowatt invested $50.0 million in the Company in the
form of shares of Preferred Stock, all of which were converted into shares of
Common Stock in connection with the Common Stock Offering.
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:
<TABLE>
<S> <C>
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, 1996 and 1995
Consolidated Statements of Operations for the Years Ended December 31, 1996,
1995 and 1994
Consolidated Statements of Shareholders' Equity for the Years Ended December
31, 1996, 1995 and 1994
Consolidated Statements of Cash Flows for the Years Ended December 31, 1996,
1995 and 1994
Notes to Consolidated Financial Statements for December 31, 1996
</TABLE>
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(A)-2. FINANCIAL STATEMENTS AND SCHEDULES
The following items appear in Appendix F of this report:
<TABLE>
<S> <C> <C>
CALPINE CORPORATION
I Condensed Financial Information of Registrant
Report of Independent Public Accountants
Balance Sheets, December 31, 1996 and 1995
Statements of Operations for the Years Ended December 31, 1996, 1995, and
1994
Statements of Cash Flows for the Years Ended December 31, 1996, 1995, and
1994
Notes to Condensed Financial Statements for December 31, 1996
II Valuation and Qualifying Accounts
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Independent Auditor's Report
Consolidated Balance Sheets, December 31, 1996 and 1995
Consolidated Statements of Operations for the Years Ended December 31, 1996,
1995 and 1994
Consolidated Statements of Changes in Partners' Equity for the Years Ended
December 31, 1996, 1995 and 1994
Consolidated Statements of Cash Flows for the Years Ended December 31, 1996,
1995 and 1994
Notes to Consolidated Financial Statements for the Years Ended December 31,
1996, 1995 and 1994
</TABLE>
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.
(A)-3. EXHIBITS
The following exhibits are filed herewith unless otherwise indicated:
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
<S> <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)
</TABLE>
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<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
<S> <C>
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)
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. *
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)
</TABLE>
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<PAGE> 41
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
<S> <C>
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)
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. *
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)
</TABLE>
39
<PAGE> 42
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
<S> <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)
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)
</TABLE>
40
<PAGE> 43
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
<S> <C>
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)
10.11 Form of Indemnification Agreement for directors and officers. (l)
21.1 Subsidiaries of the Company. (m)
</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.
41
<PAGE> 44
(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.
* Filed herewith.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the period from October 1, 1996 to
December 31, 1996.
42
<PAGE> 45
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: March 21, 1997 CALPINE CORPORATION
By: /s/ PETER CARTWRIGHT
------------------------------------
Peter Cartwright
President, Chief Executive Officer
and
Chairman of the Board
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
- ------------------------------------------ --------------------------------- ---------------
<C> <S> <C>
/s/ PETER CARTWRIGHT President, Chief Executive March 21, 1997
- ------------------------------------------ Officer and Chairman of the
Peter Cartwright Board (Principal Executive
Officer)
/s/ ANN B. CURTIS Senior Vice President and March 21, 1997
- ------------------------------------------ Director (Principal Financial
Ann B. Curtis Officer)
/s/ JEFFREY E. GARTEN Director March 21, 1997
- ------------------------------------------
Jeffrey E. Garten
</TABLE>
43
<PAGE> 46
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- ------------------------------------------ --------------------------------- ---------------
<C> <S> <C>
/s/ SUSAN C. SCHWAB Director March 21, 1997
- ------------------------------------------
Susan C. Schwab
/s/ GEORGE J. STATHAKIS Director March 21, 1997
- ------------------------------------------
George J. Stathakis
/s/ JOHN O. WILSON Director March 21, 1997
- ------------------------------------------
John O. Wilson
/s/ ORVILLE WRIGHT Director March 21, 1997
- ------------------------------------------
V. Orville Wright
/s/ GLORIA S. GEE Controller (Principal Accounting March 21, 1997
- ------------------------------------------ Officer)
Gloria S. Gee
</TABLE>
44
<PAGE> 47
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND OTHER INFORMATION
DECEMBER 31, 1996
<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-11
Consolidated Balance Sheets, December 31, 1996 and 1995............................... F-12
Consolidated Statements of Operations for the Years Ended December 31, 1996, 1995 and
1994................................................................................ F-13
Consolidated Statements of Shareholder's Equity for the Years Ended December 31, 1996,
1995 and 1994....................................................................... F-14
Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and
1994................................................................................ F-15
Notes to Consolidated Financial Statements for the Years Ended December 31, 1996, 1995
and 1994............................................................................ F-16
CALPINE CORPORATION
Schedule I: Condensed Financial Information of Registrant
Report of Independent Public Accountants............................................ F-41
Condensed Balance Sheets, December 31, 1996 and 1995................................ F-42
Condensed Statements of Operations for the Years Ended December 31, 1996, 1995 and
1994............................................................................. F-43
Condensed Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and
1994............................................................................. F-44
Notes to Condensed Financial Statements for December 31, 1996....................... F-45
Schedule II: Valuation and Qualifying Accounts........................................ F-48
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Report of Independent Public Accountants.............................................. F-49
Consolidated Balance Sheets, December 31, 1996 and 1995............................... F-50
Consolidated Statement of Income for the Years Ended December 31, 1996, 1995 and
1994................................................................................ F-51
Consolidated Statement of Changes in Partners' Equity for the Years Ended December 31,
1996, 1995 and 1994................................................................. F-52
Consolidated Statement of Cash Flows for the Years Ended December 31, 1996, 1995 and
1994................................................................................ F-53
Notes to Consolidated Financial Statements for the Years Ended December 31, 1996, 1995
and 1994............................................................................ F-54
</TABLE>
F-1
<PAGE> 48
SELECTED CONSOLIDATED FINANCIAL DATA
The consolidated financial data set forth below for and as of the five
years ended December 31, 1996 have been derived from the audited consolidated
financial statements of the Company. The following selected consolidated
financial data should be read in conjunction with the consolidated financial
statements and the related notes thereto appearing elsewhere in this report, and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1992 1993 1994 1995 1996
------- ------- ------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales............................ $ -- $53,000 $90,295 $127,799 $199,464
Service contract revenue............................... 29,817 16,896 7,221 7,153 6,455
Income (loss) from unconsolidated investments in power
projects............................................. 9,760 19 (2,754) (2,854) 6,537
Interest income on loans to power projects............. -- -- -- -- 2,098
------- ------- ------- -------- --------
Total revenue........................................ 39,577 69,915 94,762 132,098 214,554
Cost of revenue.......................................... 25,921 42,501 52,845 77,388 129,200
------- ------- ------- -------- --------
Gross profit............................................. 13,656 27,414 41,917 54,710 85,354
Project development expenses............................. 806 1,280 1,784 3,087 3,867
General and administrative expenses...................... 3,924 5,080 7,323 8,937 14,696
Compensation expense related to stock options (1)........ 1,224 -- -- -- --
Provision for write-off of project development costs
(2).................................................... 800 -- 1,038 -- --
------- ------- ------- -------- --------
Income from operations............................... 6,902 21,054 31,772 42,686 66,791
Interest expense......................................... 1,225 13,825 23,886 32,154 45,294
Other income, net........................................ (310) (1,133) (1,988) (1,895) (6,259)
------- ------- ------- -------- --------
Income before provision for income taxes and
cumulative effect of change in accounting
principle.......................................... 5,987 8,362 9,874 12,427 27,756
Provision for income taxes............................... 2,527 4,195 3,853 5,049 9,064
------- ------- ------- -------- --------
Income before cumulative effect of change in
accounting principle............................... 3,460 4,167 6,021 7,378 18,692
Cumulative effect of adoption of SFAS No. 109............ -- (413) -- -- --
------- ------- ------- -------- --------
Net income........................................... $ 3,460 $ 3,754 $ 6,021 $ 7,378 $ 18,692
======= ======= ======= ======== ========
Primary earnings per share (3) Weighted average shares
outstanding............................................ -- 14,680
======== ========
Primary earnings per share............................. -- $ 1.27
======== ========
Fully diluted earnings per share (3)
Weighted average shares outstanding.................... -- 15,130
======== ========
Fully diluted earnings per share....................... -- $ 1.24
======== ========
As adjusted primary earnings per share assuming
conversion of preferred stock (3)
Weighted average shares outstanding.................... 14,151 --
======== ========
Primary earnings per share............................. $ 0.52 --
======== ========
OTHER FINANCIAL DATA AND RATIOS:
(in thousands, except ratio data)
Depreciation and amortization............................ $ 232 $12,540 $21,580 $ 26,896 $ 40,551
EBITDA (4)............................................... $ 9,898 $42,370 $53,707 $ 69,515 $117,379
EBITDA to Consolidated Interest Expense (5).............. 4.73x 2.98x 2.23x 2.11x 2.41x
Total debt to EBITDA................................... 3.70x 6.24x 6.23x 5.87x 5.12x
Ratio of earnings to fixed charges (6)................... 3.41x 2.09x 1.52x 1.46x 1.45x
</TABLE>
See footnotes on next page)
F-2
<PAGE> 49
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------------------------------
1992 1993 1994 1995 1996
------- -------- -------- -------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents........... $ 2,160 $ 6,166 $ 22,527 $ 21,810 $ 100,010
Property, plant and equipment,
net............................... 424 251,070 335,453 447,751 650,053
Total assets........................ 55,370 302,256 421,372 554,531 1,030,215
Total liabilities................... 44,865 288,827 402,723 529,304 827,088
Stockholders' equity................ 10,505 13,429 18,649 25,227 203,127
</TABLE>
- ---------------
(1) Represents a non-cash charge for compensation expense associated with the
grant of certain options under the Company's stock option program.
(2) Represents a write-off of certain capitalized project costs.
(3) The weighted average shares outstanding and earnings per share for the year
ended December 31, 1996 gave effect to the issuance of common stock upon the
conversion of the Company's preferred stock in connection with the Company's
initial public offering (see Note 1 of Notes to Consolidated Financial
Statements). The presentation of fully diluted earnings per share for the
year ended 1996 is not required by Accounting Principles Board Opinion No.
15, because it results in dilution of less than 3%. As adjusted primary
earnings per share assuming conversion of preferred stock for the year ended
December 31, 1995 is calculated using average shares outstanding, which
includes common share equivalents using the treasury stock method and the
assumed conversion of preferred stock to common stock as of January 1, 1995
in accordance with Securities and Exchange Commission staff policy. Earnings
per share prior to 1995 have not been presented since such amounts are not
deemed meaningful due to the significant change in the Company's capital
structure that occurred in connection with its initial public offering.
(4) 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 either (i) to income from
operations (determined in accordance with generally accepted accounting
principles) or (ii) to cash flows from operating activities (determined in
accordance with generally accepted accounting principles).
(5) 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.
(6) 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> 50
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. 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 risks
and uncertainties 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, and (iii) other risks identified
from time to time in the Company's reports and registration statements filed
with the Securities and Exchange Commission.
GENERAL
Calpine is engaged in the acquisition, development, 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 interests in
15 power generation facilities and steam fields having an aggregate capacity of
1,047 megawatts. Since its inception in 1984, Calpine has developed substantial
expertise in all aspects of electric power generation. The Company's vertical
integration has resulted in significant growth over the last five years as
Calpine has applied its extensive engineering, construction management,
operations, fuel management and financing capabilities to successfully implement
its acquisition and development program. During the last five years, Calpine has
expanded substantially, from $55.4 million of total assets as of December 31,
1992 to $1.0 billion assets as of December 31, 1996. Calpine's revenue for 1996
increased to $214.6 million, representing a compound annual growth rate of 52.6%
since 1992. The Company's EBITDA (see Selected Consolidated Financial Data) for
1996 increased to $117.4 million.
On September 9, 1994, the Company acquired Thermal Power Company, which
owns a 25% undivided interest in certain steam fields at The Geysers steam
fields in northern California ("The Geysers") with a total capacity of 604
megawatts for a purchase price of $66.5 million. In January 1995, the Company
purchased the working interest in certain of the geothermal properties at the
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 natural 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 natural
gas-fired cogeneration facility, for a 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 120 megawatt King City Power Plant, 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.
Each of the power generation facilities produces electricity for sale to a
utility. Thermal energy produced by the gasfired 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. Nine of these agreements with Pacific Gas and
Electric Company ("PG&E") provides for both capacity payments and energy
payments for the term of the agreement. During the initial ten-year period of
certain agreements, PG&E pays a fixed price for each unit of electrical energy
according to schedules set forth in such agreements. The fixed price periods
under these power sales agreements expire at various times in 1998 through 2000.
After the fixed price periods expire,
F-4
<PAGE> 51
while the basis for the capacity and capacity bonus payments under these power
sales agreements remains the same, the energy payments adjust to PG&E's then
avoided cost of energy, which is determined by the California Public Utilities
Commission ("CPUC"). The currently prevailing avoided cost of energy is
substantially lower than the fixed energy prices under these power sales
agreements and is generally expected to remain so. While avoided cost does not
affect capacity payments under the power sales agreements, in the event that the
avoided cost of energy does not increase significantly, the Company's energy
revenues under these power sales agreements would 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 cannot predict the
likely level of avoided cost energy prices at the expiration of the fixed price
periods. 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.
Each of the Company's power and steam sales agreements contains 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. During
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 facilities that supply electricity. The
Company expects maximum curtailment during 1997 under its power and steam sales
agreements for certain of its facilities.
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
envisions commencement of deregulation and implementation of customer choice of
electricity supplier by January 1, 1998 (see Note 28 of the Notes to
Consolidated Financial Statements). As part of its policy decision, the CPUC
indicated that power sales agreements of existing qualifying facilities ("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. 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.
SELECTED OPERATING INFORMATION
Set forth below is certain selected operating information for the power
generation facilities and steam fields, for which results are consolidated in
the Company's 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 and the Watsonville Power
Plant since their acquisitions on April 21, 1995 and June 29, 1995,
respectively, the Gilroy Power Plant since its acquisition on August 29,1996,
and the King City Power Plant since the effective date of the lease on May 2,
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 1996, the Thermal Power Company Steam Fields since the acquisition
of Thermal Power Company 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 West Ford Flat Power Plant, Bear Canyon Power Plant, the PG&E Unit 13 and
Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields in April 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.
F-5
<PAGE> 52
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1992 1993 1994 1995 1996
---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
POWER PLANTS:
Electricity revenue (1):
Energy............................. $ 38,325 $ 37,088 $ 45,912 $ 54,886 $ 93,851
Capacity........................... $ 7,707 $ 7,834 $ 7,967 $ 30,485 $ 65,064
Megawatt hours produced............ 403,274 378,035 447,177 1,033,566 1,985,404
Average energy price per kilowatt
hour (2)........................ 9.503c 9.811c 10.267c 5.310c 4.727c
STEAM FIELDS:
Steam revenue:
Calpine......................... $ 33,385 $ 31,066 $ 32,631 $ 39,669 $ 40,549
Other interest.................. $ 2,501 $ 2,143 $ 2,051 -- --
Megawatt hours produced............ 2,105,345 2,014,758 2,156,492 2,415,059 2,528,874
Average price per kilowatt hour.... 1.705c 1.648c 1.608c 1.643c 1.603c
</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 hours since 1994 reflects the increase in
the Company's megawatt hour production as a result of acquisitions of
gas-fired cogeneration facilities by the Company.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
Revenue. Revenue increased 62% to $214.6 million in 1996 compared to
$132.1 million in 1995, primarily due to a 56% increase in electricity and steam
sales of $199.5 million in 1996 compared to $127.8 million in 1995. The King
City Power Plant and the Gilroy Power Plant contributed revenues of $41.5
million and $14.7 million, respectively, to electric and steam sales revenue
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
increases in electric and steam revenue 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 West Ford Flat and Bear Canyon Power Plants. Without such curtailment, the
West Ford Flat and Bear Canyon Power Plants would have generated an additional
$5.7 million and $5.2 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 Cogeneration Company, L.P.
("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 which
F-6
<PAGE> 53
was acquired 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 financings.
Other income, net. Other income, net increased 232% to $6.3 million for
1996 compared with $1.9 million for 1995. The increase was primarily due to $4.5
million of interest income on collateral securities purchased in connection with
the King City transaction, $1.4 million of net proceeds for the settlement of
the Coso project, and higher interest income for the period due to the
investment of the net proceeds of the preferred stock, the 10 1/2% Senior Notes
Due 2006, and from the Company's initial public offering of common shares.
Offsetting these income items was a $3.7 million loss for uncollectible amounts
related to the O'Brien acquisition project (see Note 13 of Notes to Consolidated
Financial Statements).
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 8.84% 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.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994
Revenue increased 39% to $132.1 million in 1995 compared to $94.8 million
in 1994, primarily due to a 42% increase in electricity and steam sales to
$127.8 million in 1995 compared to $90.3 million in 1994. Such an increase was
primarily attributable to the $28.3 million of revenue from the Greenleaf 1 and
2 Power Plants, $5.9 million of revenue from the Watsonville Power Plant, the
$5.2 million of additional revenue from the Thermal Power Company Steam Fields
as a result of a full year of operation in 1995, and an increase of $3.0 million
of revenue from the SMUDGEO #1 Steam Fields attributable to increased production
as a result of an extended outage during 1994. Such an increase also reflects a
substantial increase in capacity payments for electricity sales from $8.0
million in 1994 to $30.5 million in 1995 as a result of the transactions stated
above. This revenue increase was partially offset by a $2.7 million decrease in
revenue from the West Ford Flat and Bear Canyon Power Plants as a result of
curtailments by PG&E due to low gas prices and high levels of precipitation
during 1995 as compared to 1994, offset in part by contractual price increases
for 1995. Without such curtailment, the West Ford Flat and Bear Canyon Power
Plants would have generated an additional $5.2 million of revenue in 1995.
Revenue for 1995 also reflects curtailment of steam production at the Thermal
Power Company Steam Fields as a result of higher precipitation and lower gas
prices in 1995, and at the PG&E Unit 13 and Unit 16 Steam Fields as a result of
hydro-spill conditions. Without curtailment, the Thermal Power Company Steam
Fields and the PG&E Unit 13 and Unit 16 Steam Fields would have generated an
additional $5.7 million and $800,000 of revenue during 1995, respectively.
F-7
<PAGE> 54
Revenue for 1995 and 1994 reflects reversals of $2.7 million and $3.2
million, respectively, of previously deferred revenue. Company revenue from
sales of steam was previously calculated considering a future period when steam
would be delivered without receiving corresponding revenue. In May 1994, the
Company ceased deferring revenue and recognized $4.0 million of its previously
deferred revenue. Based on estimates and analyses performed by the Company, the
Company no longer expects that it will be required to make these deliveries to
SMUD. Concurrently, $800,000 of the revenue increase was reserved for future
construction of gathering systems required for future production of the steam
fields, with the offset recorded in property, plant and equipment. In October
1995, PG&E agreed to the termination of the free steam provision with respect to
the PG&E Unit 13 Steam Fields. During 1995, the Company took additional measures
regarding future capital commitments and other actions which will increase steam
production and, based on additional analyses and estimates performed, the
Company recognized the remaining $2.7 million of previously deferred revenue.
Cost of revenue. Cost of revenue increased 47% to $77.4 million in 1995
compared to $52.8 million in 1994. The increase was due to plant operating,
production royalty and depreciation and amortization expenses attributable to
(i) a full year of operations at Thermal Power Company, which was purchased on
September 9, 1994, (ii) operations at the Greenleaf 1 and 2 Power Plants
subsequent to April 21, 1995, and (iii) operations at the Watsonville Power
Plant subsequent to June 29, 1995. The increases were partially offset by lower
depreciation and production royalty expenses at the West Ford Flat and Bear
Canyon Power Plants and the PG&E Unit 13 and Unit 16 Steam Fields due to
curtailment by PG&E during 1995.
Project development expenses. Project development expenses increased to
$3.1 million in 1995 compared to $1.8 million in 1994, due to new project
development activities.
General and administrative expenses. General and administrative expenses
were $8.9 million in 1995 compared to $7.3 million in 1994. The increase in 1995
was primarily due to additional personnel and related expenses necessary to
support the Company's expanded operations.
Interest expense. Interest expense increased to $32.2 million in 1995 from
$23.9 million in 1994. Approximately $3.6 million of the increase was
attributable to a full year of interest expense incurred on the debt related to
the Thermal Power Company acquisition in September 1994 and $4.1 million of
interest expense incurred on the debt related to the Greenleaf transaction in
April 1995. In addition, 1995 included a full year of interest expense on the
9 1/4% Senior Notes Due 2004 issued on February 17, 1994.
Provision for income taxes. The effective rate for the income tax
provision was approximately 41% for 1995 and 39% for 1994. The effective rates
were based on statutory tax rates, with minor reductions for depletion in excess
of tax basis benefits. Due to curtailment of production during 1995, the
allowance for statutory depletion decreased in 1995 from 1994.
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 financings. 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,
-----------------------------------
1994 1995 1996
-------- -------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash flows from:
Operating activities.................... $ 34,196 $ 26,653 $ 59,881
Investing activities.................... (84,444) (38,497) (326,834)
Financing activities.................... 66,609 11,127 345,153
-------- -------- ---------
Total........................... $ 16,361 $ (717) $ 78,200
======== ======== =========
</TABLE>
F-8
<PAGE> 55
Operating activities for 1996 consisted of approximately $18.7 million of
net income from operations, $36.6 million of depreciation and amortization, $2.0
million in deferred income taxes, and $7.8 million net increase in operating
assets and liabilities, offset by $5.3 million of undistributed income from
unconsolidated investments in power projects.
Investing activities used $326.8 million during 1996, primarily due to
$29.9 million of capital expenditures and capitalized project costs, $98.4
million for the purchase of collateral securities, a $12.9 million loan to
Coperlasa in connection with the Cerro Prieto project, $138.1 million for the
acquisition of the Gilroy Power Plant, and a $41.6 million increase in
restricted cash requirements related to the construction of the Pasadena Power
Plant.
Financing activities provided $345.2 million of cash during 1996. The
Company issued $50.0 million of preferred stock to Electrowatt, borrowed $161.8
million of bank debt and an additional $46.9 million under the credit
facilities, received net proceeds of $174.9 million from the 10 1/2% Senior
Notes Due 2006, and received $109.2 million upon the issuance of common stock.
The Company subsequently repaid $46.2 million of bank debt, all borrowings
outstanding under the credit facilities of $66.7 million, and $84.7 million of
non-recourse project financing.
As of December 31, 1996, cash and cash equivalents were $100.0 million and
working capital was $96.2 million. For the twelve months ended December 31,
1996, working capital increased by $145.2 million and cash and cash equivalents
increased by $78.2 million as compared to the comparable period in 1995. The
increase in working capital is primarily due to remaining net proceeds from the
issuance of common stock in September 1996, and reflects the inclusion of $57.0
million of non-recourse project financing in current liabilities as of December
31, 1995. On May 16, 1996, the Company issued the 10 1/2% Senior Notes Due 2006.
A portion of the funds from the issuance of the 10 1/2% Senior Notes Due 2006
was used to refinance current bank debt and borrowings under the Credit Suisse
credit facility, and to repay the $57.0 million non-recourse indebtedness to The
Bank of Nova Scotia.
As a developer, owner and operator of power generation projects, 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.
The Company currently has outstanding $105.0 million of 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
has $180.0 million of 10 1/2% Senior Notes Due 2006 which mature on May 15, 2006
and bear interest semi-annually on May 15 and November 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 include dividends and certain purchases and investments, incur
additional indebtedness and engage in certain transactions.
At December 31, 1996, the Company had $309.3 million of non-recourse
project financing associated with power generating facilities and steam fields
at the West Ford Flat Power Plant, the Bear Canyon Power Plant, the PG&E Unit 13
and Unit 16 Steam Fields, the SMUDGEO #1 Steam Fields, the Greenleaf 1 and 2
Power Plants and the Gilroy Power Plant. As of December 31, 1996, the annual
maturities for all non-recourse project financing were $30.6 million for 1997,
$32.7 million for 1998, $24.2 million for 1999, $24.8 million for 2000, $24.6
million for 2001 and $170.5 million thereafter.
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 LIBOR or at The Bank of Nova Scotia
base rate plus a mutually agreed margin. At December 31, 1996, the Company had
no borrowings outstanding and $5.9 million of letters of credit outstanding
under the revolving credit facility (see Note 16 of Notes to Consolidated
Financial Statements). The Bank of Nova Scotia 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 payments
of certain indebtedness, pay dividends, make
F-9
<PAGE> 56
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, 1996, the Company had no borrowings under
this working capital line and $900,000 of letters of credit outstanding.
Borrowings are at prime plus 1%.
The Company also has outstanding a non-interest bearing promissory note to
Natomas Energy Company in the amount of $6.5 million representing a portion of
the September 1994 purchase price of Thermal Power Company. This note has been
discounted to yield 8% per annum and is due September 9, 1997.
The Company intends to continue to seek the use of non-recourse project
financing for new projects, where appropriate. 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, 1996, the Company had commitments for capital expenditures
in 1997 totaling $4.0 million related to various projects at its geothermal
facilities. 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. Capital expenditures for
1996 were $30.2 million compared to $17.4 million for 1995, primarily due to the
purchase of new equipment. For 1996, capital expenditures included $12.5 million
related to the Pasadena Power Plant, $4.0 million for the purchase of geothermal
leases for the Glass Mountain project, $3.1 million for the new rotor at the
PG&E Unit 13 facility, $3.2 million for geothermal well drilling, $2.1 million
for a reinjection pipeline at the Company's geothermal steam fields, and $5.4
million of capital expenditures at various cogeneration facilities.
The Company continues to pursue the acquisition and development of new
power generation projects. The Company expects to commit significant capital in
future years for the acquisition and development of these projects. 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 and 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.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENT
In February 1997, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 128, Earnings Per Share, which simplifies the standards for computing
earnings per share previously found in Accounting Principles Board Opinion
("APBO") No. 15. SFAS No. 128 replaces the presentation of primary earnings per
share with a presentation of basic earnings per share, which excludes dilution.
SFAS No. 128 also requires dual presentation of basic and diluted earnings per
share on the face of the income statement for all entities with complex capital
structures and requires a reconciliation. Diluted earnings per share is computed
similarly to fully diluted earnings per share pursuant to APBO No. 15. SFAS No.
128 must be adopted for financial statements issued for periods ending after
December 15, 1997, including interim periods; earlier application is not
permitted. SFAS No. 128 requires restatement of all prior-period earnings per
share data presented. The Company has not yet quantified the effect of adopting
SFAS No. 128.
F-10
<PAGE> 57
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, 1996
and 1995, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1996. 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 and 1995. The Company has recorded income of $6.4
million and losses of $3.0 million and $2.9 million representing its share of
the net income or loss of Sumas for the years ended December 31, 1996, 1995 and
1994, 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
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 other auditors provide a reasonable
basis for our opinion.
In our opinion, based on our audits and the report of 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, 1996 and 1995, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
March 7, 1997
F-11
<PAGE> 58
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
1996 1995
---------- --------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents.......................................... $ 100,010 $ 21,810
Accounts receivable
from related parties............................................ 2,826 2,177
from others..................................................... 39,962 17,947
Acquisition project receivables.................................... 791 8,805
Collateral securities, current portion............................. 5,470 --
Interest receivable on collateral securities....................... 1,065 --
Prepaid operating lease............................................ 12,668 --
Other current assets............................................... 8,395 5,491
---------- --------
Total current assets....................................... 171,187 56,230
Property, plant and equipment, net................................... 650,053 447,751
Investments in power projects........................................ 13,937 8,218
Collateral securities, net of current portion........................ 89,806 --
Notes receivable from related parties................................ 18,182 19,391
Notes receivable from Coperlasa...................................... 17,961 6,394
Restricted cash...................................................... 55,219 9,627
Other assets......................................................... 13,870 6,920
---------- --------
Total assets............................................... $1,030,215 $554,531
========== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of non-recourse project financing.................. $ 30,627 $ 84,708
Notes payable and short-term borrowings............................ 6,865 1,177
Accounts payable................................................... 18,363 6,876
Accrued payroll and related expenses............................... 3,912 2,789
Accrued interest payable........................................... 7,332 7,050
Other accrued expenses............................................. 7,870 2,657
---------- --------
Total current liabilities.................................. 74,969 105,257
Long-term line of credit............................................. -- 19,851
Non-recourse project financing, net of current portion............... 278,640 190,642
Notes payable........................................................ -- 6,348
Senior Notes......................................................... 285,000 105,000
Deferred income taxes, net........................................... 100,385 97,621
Deferred lease incentive............................................. 78,521 --
Other liabilities.................................................... 9,573 4,585
---------- --------
Total liabilities.......................................... 827,088 529,304
---------- --------
Commitments and contingencies (Note 28)
Stockholders' equity
Common stock, $0.01 par value per share; authorized 100,000,000
shares in 1996 and 33,760,000 shares in 1995; issued and
outstanding 19,843,400 shares in 1996 and 10,387,693 shares in
1995............................................................ 20 10
Additional paid-in capital......................................... 165,412 6,214
Retained earnings.................................................. 37,726 19,034
Cumulative translation adjustment.................................. (31) (31)
---------- --------
Total stockholders' equity................................. 203,127 25,227
---------- --------
Total liabilities and stockholders' equity................. $1,030,215 $554,531
========== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-12
<PAGE> 59
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- -------
<S> <C> <C> <C>
Revenue:
Electricity and steam sales........................... $199,464 $127,799 $90,295
Service contract revenue.............................. 6,455 7,153 7,221
Income (loss) from unconsolidated investments in power
projects........................................... 6,537 (2,854) (2,754)
Interest income on loans to power projects............ 2,098 -- --
-------- -------- -------
Total revenue................................. 214,554 132,098 94,762
-------- -------- -------
Cost of revenue:
Plant operating expenses.............................. 61,894 33,162 14,944
Depreciation.......................................... 39,818 26,264 21,202
Production royalties.................................. 10,793 10,574 11,153
Operating lease expense............................... 9,295 1,542 --
Service contract expenses............................. 7,400 5,846 5,546
-------- -------- -------
Total cost of revenue......................... 129,200 77,388 52,845
-------- -------- -------
Gross profit............................................ 85,354 54,710 41,917
Project development expenses............................ 3,867 3,087 1,784
General and administrative expenses..................... 14,696 8,937 7,323
Provision for write-off of project development costs.... -- -- 1,038
-------- -------- -------
Income from operations........................ 66,791 42,686 31,772
Other (income) expense:
Interest expense
Related party...................................... 894 1,663 375
Other.............................................. 44,400 30,491 23,511
Other income, net..................................... (6,259) (1,895) (1,988)
-------- -------- -------
Income before provision for income taxes........... 27,756 12,427 9,874
Provision for income taxes............................ 9,064 5,049 3,853
-------- -------- -------
Net income.................................... $ 18,692 $ 7,378 $ 6,021
======== ======== =======
Earnings per share:
Weighted average shares outstanding................... 14,680 -- --
======== ======== =======
Earnings per share.................................... $ 1.27 -- --
======== ======== =======
As adjusted earnings per share assuming conversion of
preferred stock:
Weighted average shares outstanding................... -- 14,151 --
======== ======== =======
Earnings per share.................................... -- $ 0.52 --
======== ======== =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-13
<PAGE> 60
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
PREFERRED STOCK COMMON STOCK ADDITIONAL CUMULATIVE
--------------- --------------- PAID-IN RETAINED TRANSLATION
SHARES AMOUNT SHARES AMOUNT CAPITAL EARNINGS ADJUSTMENT TOTAL
------ ------ ------ ------ ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1993.............. -- $ -- 10,388 $ 10 $ 6,214 $ 7,235 $(31) $ 13,428
Dividend ($0.40 per share)............ -- -- -- -- -- (800) -- (800)
Net income............................ -- -- -- -- -- 6,021 -- 6,021
------ ---- ------ --- -------- ------- ---- --------
Balance, December 31, 1994.............. -- -- 10,388 10 6,214 12,456 (31) 18,649
Dividend ($0.40 per share)............ -- -- -- -- -- (800) -- (800)
Net income............................ -- -- -- -- -- 7,378 -- 7,378
------ ---- ------ --- -------- ------- ---- --------
Balance, December 31, 1995.............. -- -- 10,388 10 6,214 19,034 (31) 25,227
Issuance of preferred stock........... 5,000 50 -- -- 49,950 -- -- 50,000
Conversion of preferred stock to
common stock........................ (5,000) (50) 2,179 3 47 -- -- --
Issuance of common stock, net......... -- -- 7,276 7 109,172 -- -- 109,179
Tax benefit from stock options
exercised........................... -- -- -- -- 29 -- -- 29
Net income............................ -- -- -- -- -- 18,692 -- 18,692
------ ---- ------ --- -------- ------- ---- --------
Balance, December 31, 1996.............. -- $ -- 19,843 $ 20 $165,412 $37,726 $(31) $203,127
====== ==== ====== === ======== ======= ==== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-14
<PAGE> 61
CALPLNE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
1996 1995 1994
--------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income................................................... $ 18,692 $ 7,378 $ 6,021
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization, net......................... 36,600 25,931 20,342
Deferred income taxes, net................................. 2,028 (1,027) 3,180
(Income) loss from unconsolidated investments in power
projects................................................ (5,263) 2,854 2,754
Provision for write-off of project development costs and
other................................................... -- -- 1,038
Change in operating assets and liabilities:
Accounts receivable..................................... (12,652) (3,354) (2,578)
Acquisition project receivables......................... 8,014 (8,805) --
Other current assets.................................... (6,521) (737) 79
Accounts payable and accrued expenses................... 15,636 6,847 6,218
Deferred revenue........................................ 3,347 (2,434) (2,858)
--------- -------- --------
Net cash provided by operating activities............. 59,881 26,653 34,196
--------- -------- --------
Cash flows from investing activities:
Acquisition of property, plant and equipment................. (24,057) (17,434) (7,023)
Acquisition of Greenleaf, net of cash on hand................ -- (14,830) --
Watsonville transaction, net of cash on hand................. -- 494 --
Acquisition of TPC, net of cash on hand...................... -- -- (62,770)
Loans to Coperlasa........................................... (12,926) (6,062) --
(Increase) decrease in notes receivable...................... 2,750 (286) (13,556)
Investment in collateral securities.......................... (98,446) -- --
King City transaction, net of cash on hand................... (11,567) -- --
Maturities of collateral securities.......................... 2,900 -- --
Acquisition of Gilroy, net of cash on hand................... (138,073) -- --
Capitalized project costs.................................... (5,887) (1,258) (175)
Decrease (increase) in restricted cash....................... (41,591) 1,186 (900)
Other, net................................................... 63 (307) (20)
--------- -------- --------
Net cash used in investing activities................. (326,834) (38,497) (84,444)
--------- -------- --------
Cash flows from financing activities:
Payment of dividends......................................... -- (800) (800)
Net borrowings from (repayments of) line of credit........... (19,851) 19,851 (52,595)
Borrowings from non-recourse project financing............... 119,760 76,026 60,000
Repayments of non-recourse project financing................. (84,708) (79,388) (12,735)
Proceeds from short-term borrowings.......................... 45,000 2,683 4,500
Repayments of short-term borrowings.......................... (46,177) (6,006) --
Proceeds from issuance of Senior Notes....................... 180,000 -- 105,000
Proceeds from issuance of preferred stock.................... 50,000 -- --
Proceeds from issuance of common stock....................... 109,208 -- --
Financing costs.............................................. (8,079) (1,239) (3,921)
Proceeds from note payable................................... -- -- 5,167
Repayment of notes payable -- FMRP........................... -- -- (36,807)
Other, net................................................... -- -- (1,200)
--------- -------- --------
Net cash provided by financing activities............. 345,153 11,127 66,609
--------- -------- --------
Net increase (decrease) in cash and cash equivalents........... 78,200 (717) 16,361
Cash and cash equivalents, beginning of period................. 21,810 22,527 6,166
--------- -------- --------
Cash and cash equivalents, end of period....................... $ 100,010 $ 21,810 $ 22,527
========= ======== ========
Supplementary information -- cash paid during the year for:
Interest..................................................... $ 43,805 $ 32,162 $ 19,890
Income taxes................................................. 6,947 4,294 683
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-15
<PAGE> 62
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") are engaged in the development, acquisition,
ownership and operation of power generation facilities in the United States and
selected international markets. The Company has ownership interests in and
operates geothermal steam fields, geothermal power generation facilities, and
natural gas-fired cogeneration facilities in northern California and Washington.
Each of the generation facilities produces electricity for sale to utilities.
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. For the year ended December 31,
1996, primarily all electricity and steam sales revenue from consolidated
subsidiaries was derived from sales to two customers in northern California (see
Note 27), of which 48% related to geothermal activities. In 1996, the Company
began marketing power and energy services to utilities and other end users.
In July 1996, the Company's Board of Directors authorized the
reincorporation of the Company into Delaware in connection with the Company's
initial public offering. In addition, the Board of Directors approved a stock
split of approximately 5.194-for-1. On September 13, 1996, the reincorporation
of the Company 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 (see Note 24).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The consolidated financial statements
include the accounts of Calpine Corporation and its wholly owned and
majority-owned subsidiaries. All significant intercompany accounts and
transactions are eliminated in consolidation. Prior to 1994, the Company
acquired Calpine Geysers Company, L.P. ("CGC"). During 1994, the Company formed
Calpine Thermal Power, Inc. ("Calpine Thermal") and Calpine Siskiyou Geothermal
Partners, L.P. (see Notes 4 and 7, respectively). Calpine Thermal acquired
Thermal Power Company ("TPC") during 1994. During 1995, the Company formed
Calpine Greenleaf Corporation ("Calpine Greenleaf"), Calpine Monterey
Cogeneration, Inc. ("CMCI") and Calpine Vapor, Inc. ("Calpine Vapor"). Calpine
Greenleaf indirectly acquired two operating gas-fired cogeneration plants (see
Note 5) and CMCI acquired an operating lease for a gas-fired cogeneration
facility (see Note 6). Calpine Vapor made loans to fund construction of new
geothermal wells in Mexico (see Note 8). During 1996, the Company formed Calpine
King City Cogen L.L.C. ("CKCC"), Calpine Gilroy Cogen, L.P. ("Gilroy"), and
Pasadena Cogeneration, L.P. CKCC completed an operating lease transaction for a
gas-fired cogeneration plant (see Note 9) and Calpine Gilroy acquired the assets
of a gas-fired cogeneration plant in California (see Note 10). In December 1996,
Pasadena Cogeneration entered into an energy sales agreement and will construct
a 240 megawatt gas-fired power plant (see Note 11).
Accounting for Jointly Owned Geothermal Properties -- The Company uses the
proportionate consolidation method to account for TPC's 25% interest in jointly
owned geothermal properties. TPC has a steam sales agreement with Pacific Gas
and Electric Company ("PG&E") pursuant to which the steam derived from its
interest in the properties is sold (see Note 4).
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
Note 7), the estimated "free steam" liability (see Note 3), receivables which
the Company believes to be collectible (see Note 15) and the realization of
deferred income taxes (see Note 21). Additionally, the Company believes that
certain industry restructuring
F-16
<PAGE> 63
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(see Note 28, Regulation and CPUC Restructuring) will not have a material effect
on existing power service agreements ("PSA") 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 CGC were
entered into prior to May 1992. Had the Company applied this principle, the
revenues of the Company recorded for the years ended December 31, 1996, 1995 and
1994, would have been approximately $16.1 million, $12.6 million, and $11.9
million less, respectively.
The Company performs operations and maintenance services for all projects
in which it has an interest, except for TPC and the geothermal investment in
Mexico. Revenue from investees is recognized on these contracts when the
services are performed. Revenue from consolidated subsidiaries is eliminated in
consolidation.
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.
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 statements of
cash flows.
Investment in Collateral Securities -- The Company's investments in
collateral securities are related to the King City transaction (see Note 9) and
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 lease payment. 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, 1996 are as follows (in thousands):
<TABLE>
<CAPTION>
UNREALIZED
AMORTIZED AGGREGATE HOLDING
COST FAIR VALUE GAINS
--------- ---------- ----------
<S> <C> <C> <C>
Debt securities issued by the United
States.................................... $54,826 $ 56,737 $1,911
Corporate debt securities................... 40,450 40,499 49
------- ------- ------
$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
and accounts / notes receivable. The Company's cash accounts are held by eight
major financial institutions. The Company's accounts / notes receivable are
concentrated within entities engaged in the energy industry, mainly within the
United States, some of which are related parties. Certain of the Company's notes
receivable are with a company in Mexico (see Note 15).
Property, Plant and Equipment -- Property, plant and equipment are stated
at cost less accumulated depreciation and amortization.
F-17
<PAGE> 64
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 Calpine Thermal. Proceeds
from the sale of geothermal properties are applied against capitalized costs,
with no gain or loss recognized.
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 thirty
years. The value of the above-market pricing provided in PSAs acquired is
recorded in property, plant and equipment and is amortized over the life of the
PSA or operating lease. 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 the results of operations.
As of December 31, 1996 and 1995, the components of property, plant and
equipment are as follows (in thousands):
<TABLE>
<CAPTION>
1996 1995
-------- --------
<S> <C> <C>
Geothermal properties.................................. $297,002 $296,495
Buildings, machinery and equipment..................... 277,572 198,358
Power sales agreement.................................. 145,957 --
Miscellaneous assets................................... 11,287 2,425
-------- --------
731,818 497,278
Less accumulated depreciation and amortization......... 100,674 60,511
-------- --------
631,144 436,767
Land................................................... 754 754
Construction in progress............................... 18,155 10,230
-------- --------
Property, plant and equipment, net................... $650,053 $447,751
======== ========
</TABLE>
Investments in Power Projects -- The Company accounts for its
unconsolidated investments in power projects under the equity method. The
Company's share of income from these investments is calculated according to the
Company's equity ownership or in accordance with the terms of the appropriate
partnership agreement (see Note 14).
Capitalized Project Costs -- The Company capitalizes project development
costs upon the execution of a memorandum of understanding or a letter of intent
for a power or steam sales agreement. These costs include
F-18
<PAGE> 65
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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.
Earnings Per Share and As Adjusted Earnings Per Share -- For the calendar
year ending after the Company's initial public offering in September 1996, net
income per share was computed using the weighted average number of common and
common equivalent shares using the treasury stock method for outstanding stock
options. Net income per share also gives effect to common equivalent shares from
convertible preferred shares from the original date of issuance that
automatically converted upon completion of the Company's initial public offering
(using the if-converted method).
For the year ended December 31, 1995, as adjusted net income per share was
computed using the weighted average number of common equivalent shares, which
includes the net additional number of shares which would be issuable upon the
exercise of outstanding stock options, assuming the Company used the proceeds
received to purchase additional shares at an assumed public offering price. Net
income per share also gives effect to common equivalent shares from preferred
stock that converted upon the closing of the Company's initial public offering
assuming such shares were outstanding from the beginning of the period in
accordance with Securities and Exchange Commission staff policy. Earnings per
share prior to 1995 have not been presented since such amounts are not deemed
meaningful due to the significant change in the Company's capital structure that
occurred in connection with its initial public offering.
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, 1996, CPSC held forward
sales and purchase contracts with notional quantities of approximately 724,000
megawatt hours and 631,600 megawatt hours, respectively.
Net open positions may exist due to the origination of new transactions and
the Company's evaluation of changing market conditions. The open position
exposes the Company to the risk that fluctuating market prices may adversely
impact its financial position or results of operations. However, the net open
position is actively managed. The impact of such fluctuations 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 currently for net
aggregate losses of the entire portfolio resulting from the effect of market
changes on the net open positions. Net gains are recognized when realized.
With respect to open power contracts, CPSC has established certain reserves
and allowances, principally for adverse changes in market conditions prior to
termination of the commitments. At December 31, 1996, the Company had recorded
allowances of approximately $917,000 which is included in Service contract
revenue in the accompanying consolidated statement of operations.
The Company's credit risk associated with power contracts results from the
risk of loss as a result of non-performance by counterparties. The Company
reviews and assesses counterparty risk to limit any material impact to its
financial position and results of operations. The Company does not anticipate
non-performance by the counterparties. The Company sets credit limits prior to
entering into transactions and has not obtained collateral or other security.
Impact of Recent Accounting Pronouncements -- In March 1995, the Financial
Accounting Standards Board ("FASB") issued Statement of Financial Accounting
Standards ("SFAS") No. 121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of. This pronouncement requires that
long-lived assets and certain identifiable intangible assets be reviewed for
impairment whenever
F-19
<PAGE> 66
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. An impairment loss is to be recognized when the sum of
undiscounted cash flows is less than the carrying amount of the asset.
Measurement of the loss for assets that the entity expects to hold and use are
to be based on the fair market value of the asset. The Company adopted SFAS No.
121 effective January 1, 1996, and determined that adoption of this
pronouncement had no material impact on the results of operations or financial
condition as of January 1, 1996.
In February 1997, the FASB issued SFAS No. 128, Earnings Per Share, which
simplifies the standards for computing earnings per share previously found in
Accounting Principles Board Opinion ("APBO") No. 15. SFAS No. 128 replaces the
presentation of primary earnings per share with a presentation of basic earnings
per share, which excludes dilution. SFAS No. 128 also requires dual presentation
of basic and diluted earnings per share on the face of the income statement for
all entities with complex capital structures and requires a reconciliation.
Diluted earnings per share is computed similarly to fully diluted earnings per
share pursuant to APBO No. 15. SFAS No. 128 must be adopted for financial
statements issued for periods ending after December 15, 1997, including interim
periods; earlier application is not permitted. SFAS No. 128 requires restatement
of all prior-period earnings per share data presented. The Company has not yet
quantified the effect of adopting SFAS No. 128.
Reclassifications -- Prior years' amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1996
presentation.
3. CALPINE GEYSERS COMPANY, L.P.
CGC, a wholly owned subsidiary of the Company, is the owner of two
operating geothermal power plants and their respective steam fields, Bear Canyon
and West Ford Flat, and three geothermal steam fields, which provide steam to
PG&E's Unit 13 and Unit 16 power plants and to Sacramento Municipal Utility
District's ("SMUD") geothermal power plant. The power plants and steam fields
are located in The Geysers area of northern California. Electricity from CGC's
two operating geothermal power plants is sold to PG&E under 20-year agreements.
Under the PG&E Unit 16 and the SMUD agreements, if the quantity of steam
delivered is less than 50% of the units' capacities, then neither PG&E nor SMUD
is required to make payment for steam delivered during such month until the cost
of the affected power plant has been completely amortized. Further, both PG&E
and SMUD can terminate their agreements with written notice under conditions
specified in the agreement if further operation of the plants becomes
uneconomical. In the event that CGC terminates the agreements, PG&E or SMUD may
require CGC to assign them all rights, title and interest to the wells, lands
and related facilities. In consideration for such an assignment to SMUD, SMUD
shall reimburse CGC for its original costs net of depreciation for any
associated materials or facilities.
CGC revenues from sales of steam were calculated considering a future
period when steam would be delivered without receiving corresponding revenue.
The estimated "free steam" obligation was recorded at an average rate over
future steam production as deferred revenue in 1993. As of December 31, 1993,
the Company had deferred revenue of $8.6 million. During 1994, based on
estimates and analyses performed, the Company determined that these deliveries
would no longer be required for a customer and reversed approximately $5.9
million of its deferred revenue liability. This reversal was recorded as a $1.9
million purchase price reduction to property, plant and equipment, with the
remaining $4.0 million as an increase in revenue. Concurrently, $800,000 of the
revenue increase was reserved for future construction of gathering systems
required for future production of the steam fields, with the offset recorded in
property, plant and equipment.
In October 1994, PG&E agreed to the termination of the free steam provision
for one of the geothermal steam fields. During 1995, CGC took additional
measures regarding future capital commitments and other
F-20
<PAGE> 67
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
actions which will increase steam production and, based on additional analyses
and estimates performed, the Company recognized the remaining $2.7 million of
previously deferred revenue.
On April 19, 1993, the Company acquired Freeport-McMoRan Resource Partners,
L.P.'s ("FMRP") interest in CGC for $23.0 million in cash and non-recourse notes
payable to FMRP totaling $40.5 million. On February 17, 1994, the Company
exercised its option to prepay the notes utilizing a discount rate of 10% by
paying $36.9 million including interest in full satisfaction of its obligations
under the FMRP notes. The difference between the original carrying amount of the
notes and the prepayment was recorded as an adjustment to the purchase price.
4. CALPINE THERMAL POWER, INC.
On September 9, 1994, Calpine Thermal acquired the outstanding capital
stock of TPC for a total purchase price of $66.5 million, consisting of a $60.0
million cash payment and the issuance by Calpine of a non-interest bearing
promissory note to Natomas in the amount of $6.5 million (discounted to $5.2
million), which is due September 9, 1997. Calpine received payments of $3.0
million from the seller, which represented cash from TPC's operations for the
period from July 1, 1994 to September 8, 1994. These payments were treated as
purchase price adjustments.
Calpine Thermal owns a 25% undivided interest in certain producing
geothermal steam fields located at The Geysers area of northern California.
Union Oil Company of California owns the remaining 75% interest in the steam
fields, which deliver geothermal steam to twelve operating plants owned by PG&E.
The steam fields currently provide the twelve operating plants with sufficient
steam to generate approximately 604 megawatts of electricity.
Steam from Calpine Thermal's steam field is sold to PG&E under a steam
sales agreement. In addition, Calpine Thermal receives a monthly capacity
maintenance fee, which provides for effluent disposal costs and facilities
support costs, and a monthly fee for PG&E's right to curtail its power plants.
The steam price, capacity maintenance and curtailment fees are adjusted
annually. Calpine Thermal is required to compensate PG&E for the unused capacity
of its geothermal power plants due to insufficient field capacities of its steam
supply (offset payment).
In accordance with the steam sales agreement, PG&E may curtail the power
plants which receive steam from the Union Oil/Calpine Thermal Steam Fields in
order to produce energy from lower cost sources. However, PG&E is constrained by
its contractual obligation to operate all the power plants at a minimum of 40%
of the field capacity during any given year. During 1995 and 1996, Calpine
Thermal experienced extensive curtailments of steam production due to low gas
prices and abundant hydro power.
In March 1996, the Company 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 PG&E would
likely curtail under the existing steam sales agreement. The price for this
portion of steam will be set by the Company and Union Oil with the intent that
it be at competitive prices.
The steam sales agreement between Calpine Thermal and PG&E terminates two
years after the closing of the last PG&E operating unit. PG&E may terminate the
agreement upon a one-year written notice to Calpine Thermal. In the event the
agreement is terminated by PG&E, Calpine Thermal has the right to purchase
PG&E's facilities at PG&E's unamortized cost. Calpine Thermal will provide
capacity maintenance services for five years after termination by PG&E or
closure of the last PG&E operating unit. Alternatively, Calpine Thermal may
terminate the agreement upon a two-year written notice to PG&E. PG&E has the
right to take assignment of Calpine Thermal's facilities on the date of
termination. In such a case, Calpine Thermal would generally continue to pay
offset payments for 36 months following the date of termination.
F-21
<PAGE> 68
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. CALPINE GREENLEAF CORPORATION
On April 21, 1995, Calpine Greenleaf 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.
The acquisition was accounted for as a purchase, and the purchase price has
been allocated to the acquired assets and liabilities based on their estimated
fair values. The adjusted allocation of the purchase price is as follows (in
thousands):
<TABLE>
<S> <C>
Current assets.................................................... $ 6,572
Property, plant and equipment..................................... 122,545
---------
Total assets................................................. 129,117
---------
Current liabilities............................................... (1,079)
Deferred income taxes, net........................................ (46,580)
---------
Total liabilities............................................... (47,659)
---------
Net purchase price................................................ $ 81,458
=========
</TABLE>
The Acquired Companies own 100% of the assets of two 49.5 megawatt natural
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 PG&E
pursuant to two long-term PSAs (expiring in 2019) at prices equal to PG&E's full
short-run avoided operating costs, adjusted annually. The PSA 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. The thermal energy
generated is used by thermal hosts adjacent to the Greenleaf Power Plants.
Gas for the Greenleaf Power Plants is supplied by Montis Niger, Inc.
("MNI"). On January 31, 1997, the Company purchased MNI for $7.5 million.
6. CALPINE MONTEREY COGENERATION, INC.
On June 29, 1995, CMCI acquired a 14.5-year operating lease (through
December 2009) for a 28.5 megawatt natural gas-fired cogeneration power plant
located in Watsonville, California. The Company acquired the operating lease
from Ford Motor Credit Company for $900,000. The Watsonville Power Plant sells
electricity to PG&E under a 20-year PSA, generally at prices equal to PG&E's
full short-run avoided operating costs. Basic and contingent lease rental
payments are described in Note 26. The power plant also provides steam to two
local food processing plants. The Company also provides project and fuels
management services.
7. CALPINE SISKIYOU GEOTHERMAL PARTNERS, L.P.
In 1994, the Company formed a partnership with Trans-Pacific Geothermal
Corporation ("TGC") to build a geothermal power generation facility located at
Glass Mountain in northern California. TGC had previously signed a memorandum of
understanding ("MOU") with Bonneville Power Administration ("BPA") and the
Springfield, Oregon Utility Board ("SUB") to develop the project at Vale,
Oregon. BPA and SUB consented in August 1994 to the assignment of the MOU to the
partnership and the relocation of the project to Glass Mountain. The MOU
contemplated execution of a 45-year power purchase agreement subject to
satisfaction of certain conditions precedent and included an option for an
additional 100 megawatts. The partnership is consolidated as the Company owns a
controlling interest.
F-22
<PAGE> 69
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In December 1996, the partnership and BPA entered into a settlement
agreement which restructured the rights and obligations of the parties. In
return for the payment of $12.0 million by BPA to the partnership and the grant
by the partnership to BPA of future options to purchase power at Glass Mountain,
the partnership and BPA terminated the MOU and certain ancillary agreements. In
addition, BPA will pay the partnership additional consideration should certain
future events occur related to the ongoing environmental review of the Glass
Mountain project. Following the settlement with BPA, TGC withdrew from the
partnership.
Of the $12.0 million received by the partnership in December 1996, $4.7
million was allocated to TGC, of which $3.0 million was received by the Company
in payment of a loan (see Note 15). Previously capitalized project costs were
charged to expense, and no significant gain or loss was included in net income
for the year 1996.
At December 31, 1996, the Company had $4.0 million of geothermal leases at
Glass Mountain recorded as Property, plant and equipment, net in the
accompanying consolidated balance sheet. 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.
8. CALPINE VAPOR, INC.
In November 1995, Calpine Vapor entered into agreements with Constructora y
Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain Mexican bank lenders
to loan funds to Coperlasa in connection with a geothermal steam production
contract at the Cerro Prieto geothermal resource in Baja California, Mexico. 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. Calpine Vapor loaned
$18.5 million to Coperlasa, and received fees for technical services provided to
the project. At December 31, 1996, notes receivable (see Note 15) totaled $18.0
million. 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.
In December 1995, Calpine Vapor also paid $1.5 million for an option to
purchase an equity interest in Coperlasa. The option is being amortized over the
estimated repayment period of the Coperlasa loan and is included in Other
assets.
9. 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 natural
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 PSA through
2019 and provides steam to a vegetable processing plant.
The Company makes semi-annual lease payments to BAF on each February 15 and
August 15, a portion of which is supported by a $95.0 million collateral fund
owned by the Company. The collateral fund consists of investment grade and U.S.
Treasury Securities that mature serially in amounts equal to a portion of the
lease payment. The collateral fund securities are classified as held-to-maturity
investments (see Note 2). As of December 31, 1996, future rent payments are
$24.4 million for 1997, $23.8 million for 1998, $19.4 million for 1999, $20.1
million for 2000, $20.8 million for 2001, and $183.2 million thereafter.
Included in the accompanying December 31, 1996 balance sheet is approximately
$12.7 million of unamortized prepaid lease costs.
The Company recorded the value of the above-market pricing provided in the
PSA as an asset which is included in property, plant and equipment. The Company
has also recorded a deferred lease incentive of $78.5 million at December 31,
1996 equal to the value of the above-market payments to be received. The asset
and liability are being amortized over the life of the power sales agreement and
lease, respectively.
F-23
<PAGE> 70
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. GILROY TRANSACTION
On August 29, 1996, the Company acquired a 120 megawatt natural 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. The Company recorded the value of the above-market
pricing provided in the PSA of $82.1 million as an asset which is included in
Property, plant and equipment.
Electricity generated by the Gilroy Power Plant is sold to PG&E pursuant to
a long-term PSA terminating in 2018. The PSA 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 transactions had occurred
on January 1, 1995 (in thousands, except per share amounts):
<TABLE>
<CAPTION>
1996 1995
-------- --------
<S> <C> <C>
Revenue................................................ $237,924 $221,447
Net income............................................. $ 18,954 $ 11,288
Earnings per share..................................... $ 1.29 $ 0.80
</TABLE>
11. PASADENA COGENERATION PROJECT
The Company 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. In December 1996, 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. The Company provided a $3.0 million letter of credit to
Phillips to secure the performance under the project development agreement. The
Company also entered into a credit agreement with ING U.S. Capital Corporation
to provide $98.6 million of non-recourse project financing. In accordance with
the credit agreement, the Company contributed $53.1 million in cash to the
project, of which the remaining $41.0 million is included in Restricted cash in
the accompanying consolidated balance sheet. The Company commenced construction
in February 1997, with commercial operation scheduled to begin in October 1998.
There can be no assurances that the Company will be successful in completing any
additional PSAs or that the anticipated schedule for construction will be met.
12. ACCOUNTS RECEIVABLE
At December 31, 1996, accounts receivable of $42.8 million included $1.9
million to be received from the Los Angeles Department of Water and Power for
reimbursement of costs related to the Coso development project incurred by the
Company in prior years. Such amount was received in 1997.
F-24
<PAGE> 71
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Accounts receivable from related parties at December 31, 1996 and 1995
include the following (in thousands):
<TABLE>
<CAPTION>
1996 1995
------ ------
<S> <C> <C>
O.L.S. Energy-Agnews, Inc.................................. $ 687 $ 806
Geothermal Energy Partners, Ltd. .......................... 350 462
Sumas Cogeneration Company, L.P............................ 590 908
Electrowatt Ltd. and subsidiaries.......................... 1,199 1
------ ------
$2,826 $2,177
====== ======
</TABLE>
At December 31, 1996, the $1.2 million receivable from Electrowatt Ltd. was
for reimbursement of costs for the sale of Electrowatt's ownership of Calpine
common stock during the Company's initial public offering.
13. ACQUISITION PROJECT RECEIVABLES
In connection with an unsuccessful bid to acquire O'Brien Environmental
Energy, Inc. ("OEE") in 1995 through the U.S. Bankruptcy Court, the Company
incurred and capitalized project acquisition costs. On November 8, 1996, the
court denied Calpine's application for approval of such costs and fees and the
Company recorded a $3.7 million loss for unrecoverable amounts (included in
Other income, net in the accompanying consolidated statement of operations). The
Company is appealing the court's decision.
The Company also purchased $1.9 million of accounts receivable from two
subsidiaries of OEE. Payments were made to the Company based on cash
availability for each subsidiary. In February 1996, the Company received
approximately $1.1 million against these receivables.
The Company purchased for $900,000 from Stewart & Stevenson, Inc. ("S&S") a
participation interest in a $1.0 million note issued by OEE. The Company
received principal plus accrued interest in 1996.
The Company purchased all of S&S's rights and obligations in a Subordinated
Loan Agreement and Note between S&S and O'Brien (Newark) Cogeneration, Inc. The
purchase price was $2.8 million and the notes bore interest at prime plus 2.0%.
The Company received principal plus accrued interest in 1996.
14. INVESTMENTS IN POWER PROJECTS
The Company has unconsolidated investments in power projects which are
accounted for under the equity method. Financial information related to these
investments is as follows (in thousands):
<TABLE>
<CAPTION>
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
L.P. INC. LTD.
------------ ------------ ------------
<S> <C> <C> <C>
1996
Operating revenue.............................. $ 44,092 $ 11,023 $ 22,302
Net income (loss).............................. 8,494 (840) 6,367
Assets......................................... 129,273 37,160 69,249
Liabilities.................................... 125,652 36,711 38,304
Company's percentage ownership................. (a) 20% 5%
Equity investments in power projects........... 11,382 124 1,556
Project development costs...................... 875 -- --
-------- ------- -------
Total investments in power projects............ 12,257 124 1,556
======== ======= =======
Company's share of net income (loss)........... $ 6,396 $ (190) $ 331
======== ======= =======
</TABLE>
F-25
<PAGE> 72
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
L.P. INC. LTD.
------------ ------------ ------------
<S> <C> <C> <C>
1995
Operating revenue.............................. $ 31,526 $ 10,779 $ 21,676
Net income (loss).............................. (6,098) (483) 5,538
Assets......................................... 122,802 40,330 76,017
Liabilities.................................... 123,377 39,034 51,439
Company's percentage ownership................. (a) 20% 5%
Equity investments in power projects........... 5,763 314 1,229
Project development costs...................... 912 -- --
-------- ------- -------
Total investments in power projects............ 6,675 314 1,229
======== ======= =======
Company's share of net income (loss)........... $ (3,049) $ (82) $ 227
======== ======= =======
</TABLE>
<TABLE>
<CAPTION>
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
L.P. INC. LTD.
------------ ------------ ------------
<S> <C> <C> <C>
1994
Operating revenue.............................. $ 32,060 $ 11,985 $ 21,721
Net income (loss).............................. (5,777) (415) 5,548
Assets......................................... 130,148 42,596 77,081
Liabilities.................................... 124,625 40,864 58,041
Company's percentage ownership................. (a) 20% 5%
Equity investments in power projects........... 8,812 396 952
Project development costs...................... 946 8 --
-------- ------- -------
Total investments in power projects............ 9,758 404 952
======== ======= =======
Company's share of net income (loss)........... $ (2,888) $ (143) $ 277
======== ======= =======
</TABLE>
- ---------------
(a) Distributions will be made out of operating income after certain required
deposits are made and certain minimum balances are met. After receiving
certain preferential distributions, the Company will have a 50% interest in
the profits and losses of Sumas until earning a 24.5% pre-tax cumulative
return on its investment, at which time the Company's interest in Sumas will
be reduced to 11.33%.
Sumas Cogeneration Company, L.P. -- Sumas Cogeneration Company, L P.
("Sumas") is a Delaware limited partnership formed between Sumas Energy, Inc.
("SEI"), a Washington State Subchapter S corporation, and Whatcom Cogeneration
Partners, L.P. ("Whatcom"), a wholly owned partnership of the Company. SEI is
the general partner and Whatcom is the limited partner. Sumas has a wholly owned
Canadian subsidiary, ENCO Gas, Ltd. ("ENCO"), which is incorporated in New
Brunswick, Canada.
Sumas owns and operates a 125 megawatt natural gas-fired cogeneration power
plant. In connection with the Sumas power plant is a lumber dry kiln facility
and a 3.5 mile private natural gas pipeline. ENCO acquired, developed and is
operating a portfolio of proven natural gas reserves in British Columbia and
Alberta, Canada to provide a dedicated fuel supply for the Sumas Power Plant.
Sumas produces and sells electrical energy to Puget Sound Power & Light
Company ("Puget") under a 20-year agreement for an average 123 megawatts. Sumas
leases the dry kiln facility and sells steam to Socco, Inc. ("Socco"), a custom
lumber drying operation owned by an affiliated individual.
F-26
<PAGE> 73
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Construction financing was provided through a $95.2 million construction
and term loan agreement with The Prudential Insurance Company of America
("Prudential") and Credit Suisse, an affiliate of the Company. In addition, ENCO
has a $24.8 million loan agreement with Prudential and Credit Suisse. On May 25,
1993, the entire $120.0 million was converted to a term loan.
In addition, the Company provides operations and maintenance services to
Sumas and receives a fixed fee of $1.1 million per year adjusted annually for
inflation, an annual base fee of $150,000 per year also adjusted annually for
inflation and certain other reimbursable expenses. The Company is entitled to an
annual performance bonus of up to $400,000 based upon the achievement of certain
performance levels. This arrangement will expire upon the date Whatcom receives
its 24.5% pre-tax return or 10 years, subject to renewal terms, whichever is
later. The Company recorded revenue of approximately $2.0 million, $2.0 million,
and $1.9 million associated with this arrangement during the years ended
December 31, 1996, 1995 and 1994, respectively.
O.L.S. Energy-Agnews, Inc. -- The Company has a 20% interest in O.L.S.
Energy-Agnews, Inc., a joint venture with GATX Capital Corporation, which owns
and operates a 29 megawatt gas-fired combined-cycle cogeneration facility at the
State-owned Agnews Developmental Center ("Center") in San Jose, California. The
cogeneration plant provides the Center with all of its thermal and electric
requirements. Excess electricity is sold to PG&E under a Standard Offer No. 4
contract. The Company's original investment was $1.8 million.
In addition to its interest as stated above, the Company has been
contracted by the joint venture to provide operations and maintenance services
at cost plus overhead and fees, as specified. The Company recorded revenue of
$2.0 million, $1.5 million, and $1.4 million associated with this service
agreement and for other services provided to the joint venture for the years
ended December 31, 1996, 1995 and 1994, respectively.
In January 1990, O.L.S Energy-Agnews, Inc. entered into a credit agreement
with Credit Suisse providing for a $28.0 million loan. The loan is secured by
all of the assets of the Agnews Power Plant and bears interest on the unpaid
principal balance based on the London Interbank Offered Rate ("LIBOR") plus a
margin rate varying between 0.05% and 1.5%.
Geothermal Energy Partners, Ltd. -- During 1989, the Company acquired a 5%
interest in Geothermal Energy Partners Ltd. ("GEP"). GEP was established in 1988
to develop, finance and construct a 20 megawatt geothermal power production
facility located in The Geysers area of northern California. The facility began
operations on June 6, 1989.
In addition to its interest as stated above, the Company has been
contracted by GEP to provide operations and maintenance services at cost plus
overhead and fees, as specified. The Company recorded revenue of $4.0 million,
$3.5 million and $3.7 million associated with this service agreement to GEP for
the years ended December 31, 1996, 1995 and 1994, respectively.
The Company accounts for its investment in GEP under the equity method
because control of the project is deemed to be shared under the terms of the
partnership agreement, and the Company has significant influence over the
operation of the venture.
15. NOTES RECEIVABLE
In May 1993, in accordance with the Sumas partnership agreement, the
Company was entitled to receive a distribution of $1.5 million and 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 loan
bears interest at 20% and is secured by a security interest in the loan between
SEI and its sole shareholder. The Company will receive payments of 50% of SEI's
cash
F-27
<PAGE> 74
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
distributions from Sumas. The payments will first reduce any accrued and unpaid
interest and then reduce the principal balance. On May 25, 2003, all unpaid
principal and interest is due.
In March 1994, the Company loaned $10.0 million to the sole shareholder of
SEI. The loan matures in 10 years and bears interest at 16.25%. The loan is
secured by a pledge to Calpine of SEI's interest in Sumas. In order to provide
for the payment of principal and interest on the loan, an additional 12 1/2% of
the cash flow generated by Sumas was assigned to Calpine. The Company deferred
the recognition of interest income from these notes until Sumas generated net
income. In 1996, the Company recognized a total of $2.1 million of interest
income related to the above two loans, which represents the portion of Sumas'
earnings not recognized by Calpine related to its equity investment in Sumas.
In August 1994, the Company entered into a loan agreement providing for
loans up to $4.8 million to Trans-Pacific Geothermal Glass Mountain Ltd.
("TGGM"), a subsidiary of TGC (see Note 7). The loan bore interest at 10% and
had a maturity date which was based on certain future events. The loan was
secured by a pledge to Calpine of the partner's interest in the Glass Mountain
project. The Company was deferring the recognition of income from this note
until the Glass Mountain project generated sufficient income to support the
collectibility of interest earned. At December 1, 1996, $4.1 million was
outstanding. In December 1996, the Company received $3.0 million from TGGM in
payment of the loan and recorded a $1.1 million loss for uncollectible amounts,
which was included in Other income, net (see Note 7).
As of December 31, 1996, Calpine Vapor had notes receivable of $18.0
million from Coperlasa and associated unamortized loan acquisition fees of $1.1
million (see Note 8). Interest accrues on the outstanding notes receivable at
approximately 18.9%. The Company is deferring the recognition of income from
this note until the Cerro Prieto project generates sufficient cash flows
available for distribution to support the collectibility of interest earned.
16. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
At December 31, 1996, the Company had a $50.0 million three-year credit
facility available with a consortium of commercial lending institutions which
include The Bank of Nova Scotia, International Nederlanden U.S. Capital
Corporation, Sumitomo Bank of California and Canadian Imperial Bank of Commerce.
As of December 31, 1996, the Company had no borrowings and $5.9 million of
letters of credit outstanding, which reflect $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 or at
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, 1995, the Company had a $50.0 million credit facility with
Credit Suisse (whose parent company owns approximately 44.9% of Electrowatt Ltd.
("Electrowatt"), the former indirect sole owner of the Company prior to the
initial public offering on September 25, 1996). At December 31, 1995, the
Company had $19.9 million of borrowings outstanding, bearing interest at LIBOR
plus 0.5% (6.4% at December 31, 1995). Interest could be paid at either LIBOR or
the Credit Suisse base rate, plus applicable margins in both cases. The credit
agreement specified that the Company maintain certain covenants with which the
Company was in compliance. The Company terminated its Credit Suisse credit
facility on September 25, 1996.
At December 31, 1996, the Company had a loan facility with available
borrowings totaling $1.2 million. There were no borrowings and $900,000 of
letters of credit outstanding as of December 31, 1996. At December 31, 1995, the
Company had three loan facilities with available borrowings totaling $10.2
million.
F-28
<PAGE> 75
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Borrowings and letters of credit outstanding were $1.2 million and $3.8 million
as of December 31, 1995, respectively. Interest is payable at variable interest
rates based on bank base rates, LIBOR or prime plus applicable margins in all
cases (approximately 7.6% at December 31, 1995 on borrowings). The credit
agreements specified that the Company maintain certain covenants with which the
Company was in compliance.
17. WORKING CAPITAL LOAN
The Company has a $5.0 million working capital loan agreement with a bank
providing for advances and letters of credit. The aggregate unpaid principal of
the working capital loan is payable in full at least once a year, with the final
payment of principal, interest and fees due June 30, 1998. Interest on
borrowings accrues at the option of the Company at either a base rate, LIBOR, or
a certificate of deposit rate (plus applicable margins in all cases) over the
term of the loan. No borrowings were outstanding at December 31, 1996 and 1995.
The Company had letters of credit outstanding of $459,000 at December 31, 1996
and 1995. Outstanding letters of credit bear interest at 0.625% payable
quarterly.
18. NON-RECOURSE PROJECT FINANCING
The components of non-recourse project financing as of December 31, 1996
and 1995 are (in thousands):
<TABLE>
<CAPTION>
1996 1995
-------- --------
<S> <C> <C>
Senior-term loans:
Fixed rate portion................................... $ 73,000 $ 99,400
Variable rate portion................................ 20,000 20,000
Premium on debt...................................... 1,824 2,959
-------- --------
Total senior-term loans...................... 94,824 122,359
Junior-term loans...................................... 19,965 19,965
Notes payable to banks................................. 194,478 133,026
-------- --------
Total long-term debt......................... 309,267 275,350
Less current portion......................... 30,627 84,708
-------- --------
Long-term debt, less current portion......... $278,640 $190,642
======== ========
</TABLE>
The Company entered into the Senior-Term Loans and Junior-Term Loans in
connection with the Company's acquisition of CGC in 1993.
Senior-Term Loans -- Principal and interest are payable in quarterly
installments at variable amounts with the final payment of principal, interest
and fees due June 30, 2002. A portion of the senior-term loans bears interest
fixed at 9.93% (see discussion on swap agreement below) with the remainder
accruing interest at LIBOR plus an applicable margin (6.75% and 6.69% at
December 31, 1996 and 1995, respectively) over the term of the loan,
collateralized by all of CGC's assets and the Company's interest in CGC. The
premium is amortized over the life of the fixed rate portion of the loan using
the interest method.
Junior-Term Loans -- Principal and interest are payable in quarterly
installments at variable amounts beginning September 30, 2002 with the final
payment of principal, interest and fees due June 30, 2005; interest accrues at
LIBOR plus an applicable margin (7.75% and 7.69% at December 31, 1996 and 1995,
respectively) over the term of the loan, collateralized by all of CGC's assets
and the Company's interest in CGC.
The Company entered into two interest rate swap agreements to minimize the
impact of changes in interest rates on a portion of its senior-term loans. These
agreements fix the interest on this portion at 9.93%. At December 31, 1996, the
swap agreements applied to debt with a principal balance total of $73.0 million.
The interest rate swap agreements mature through December 31, 2000. The premium
on debt was recorded in
F-29
<PAGE> 76
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
conjunction with the acquisition as discussed above. The amortization of the
premium adjusts the effective interest rate on the fixed-rate debt to 7.05% per
annum. The floating interest rate associated with this portion of the
senior-term loans was LIBOR plus an applicable margin (6.63% at December 31,
1996 and 6.99% at December 31, 1995). The Company is exposed to credit risk in
the event of non-performance by the other parties to the swap agreements.
Notes Payable to Banks -- In September 1994, the Company entered into a
two-year agreement with The Bank of Nova Scotia to finance the acquisition of
TPC. In May 1996, a portion of the net proceeds from the Company's issuance of
the 10 1/2% Senior Notes Due 2006 was utilized to repay the total $57.0 million
of borrowings under this agreement.
In June 1995, the Company entered into an agreement with Sumitomo Bank to
finance the acquisition of the Greenleaf Power Plants. Of the $74.7 million debt
outstanding at December 31, 1996, $59.0 million bears interest fixed at 7.4%,
with the remaining floating rate portion accruing interest at LIBOR plus an
applicable margin (6.24% as of December 31, 1996). At December 31, 1995, $76.0
million of debt was outstanding, of which $60.0 million was at the fixed
interest rate of 7.4%, with the remaining floating rate portion accruing
interest at approximately 6.5%. This debt is secured by all of the assets of
Greenleaf 1 and 2. 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 $74.7 million debt will be
repaid quarterly, with a final maturity date of December 31, 2010.
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, 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. In addition, BNP provided two additional tranches for
the payment of certain contingent consideration, which at December 31, 1996
totaled $19.6 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% (see discussion below), with the remainder accruing interest at
LIBOR plus an applicable margin (6.6% at December 31, 1996). Interest on the
floating rate portion may be at BNP's base rate plus an applicable margin or at
LIBOR plus an applicable margin. Interest on base rate 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 $119.8 million debt will be repaid semi-annually beginning
August 31, 1997, 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 $87.5
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.
F-30
<PAGE> 77
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The annual principal maturities of the non-recourse debt outstanding at
December 31, 1996 are as follows (in thousands):
<TABLE>
<S> <C>
1997.............................................. $ 30,627
1998.............................................. 32,658
1999.............................................. 24,183
2000.............................................. 24,851
2001.............................................. 24,631
Thereafter........................................ 170,493
--------
307,443
Unamortized premium on fixed portion of senior
loans........................................... 1,824
--------
Total................................... $309,267
========
</TABLE>
The carrying value of $73.0 million and $99.4 million of the senior-term
loan as of December 31, 1996 and 1995, respectively, has an effective rate of
9.93% under the Company's interest rate swap agreements (7.05% after
consideration of the debt premium). Based on the borrowing rates currently
available to the Company for bank loans with similar terms and maturities, the
fair value of the debt as of December 31, 1996 and 1995 is approximately $83.2
million and $107.3 million, respectively. The carrying value of the remaining
$20.0 million of the senior-term and the $20.0 million junior-term loans and the
notes payable to banks approximate the debts' fair market value as the rates are
variable and based on the current LIBOR rate.
The non-recourse debt is held by subsidiaries of Calpine. 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.
On December 20, 1996, the Company entered into a credit agreement with ING
U.S. Capital Corporation to provide $98.6 million of non-recourse project
financing for the Pasadena Cogeneration Project (see Note 11). No borrowings
were outstanding at December 31, 1996. 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 no less 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.
19. 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 has been discounted to yield 8.0%
per annum, due September 9, 1997. The carrying amount of $6.2 million at
December 31, 1996 approximates fair market value.
In January 1995, the Company purchased the working interest covering
certain properties in its geothermal properties at CGC from Santa Fe Geothermal,
Inc. The purchase price included $6.0 million cash, and a $750,000 non-interest
bearing note discounted to yield 9% per annum and due on December 26, 1997. The
Company may repay all or any part of the note at any time without penalty. The
carrying value of $686,000 of the discounted non-interest bearing note at
December 31, 1996 approximates fair market value.
F-31
<PAGE> 78
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
20. SENIOR NOTES
On May 16, 1996, the Company issued $180.0 million aggregate principal
amount of 10 1/2% Senior Notes Due 2006. The net proceeds of $174.9 million were
used to repay $53.7 million of borrowings under the Credit Suisse Credit
Facility, $57.0 million of non-recourse project financing and $45.0 million of
borrowings from The Bank of Nova Scotia. The remaining $19.2 million was
available for general corporate purposes. Transaction costs of $5.1 million
incurred in connection with the public debt offering were recorded as a deferred
charge and are amortized over the ten-year life of the 10 1/2% Senior Notes Due
2006.
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 $191.7 million as of December 31,
1996.
On February 17, 1994, the Company completed a $105.0 million public debt
offering of 9 1/4% Senior Notes Due 2004. Transaction costs of $4.1 million
incurred in connection with the public debt offering were recorded as a deferred
charge and are amortized over the ten-year life of the 9 1/4% Senior Notes Due
2004.
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 $105.7 million as of
December 31, 1996.
The Senior Note indentures specify that the Company maintain 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.
21. 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, 1996 and
1995 are (in thousands):
<TABLE>
<CAPTION>
1996 1995
--------- ---------
<S> <C> <C>
Expenses deductible in a future period............... $ 3,329 $ 1,674
Net operating loss and credit carryforwards.......... 19,856 19,480
Other differences.................................... 1,186 2,034
--------- ---------
Deferred tax asset, before valuation allowance..... 24,371 23,188
Valuation allowance.................................. (692) (749)
--------- ---------
Deferred tax asset................................. 23,679 22,439
--------- ---------
Property differences................................. (119,842) (116,314)
Difference in taxable income and income from
investments recorded on the equity method.......... (2,753) (2,311)
Other differences.................................... (1,469) (1,435)
--------- ---------
Deferred tax liabilities........................... (124,064) (120,060)
--------- ---------
Net deferred tax liability...................... $(100,385) $ (97,621)
========= =========
</TABLE>
F-32
<PAGE> 79
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The net operating loss and credit carryforwards consist of Federal and
State net operating loss carryforwards which expire 2005 through 2010 and 2000,
respectively, and Federal and State alternative minimum tax credit carryforwards
which can be carried forward indefinitely. At December 31, 1996, the Federal and
State net operating loss carryforwards were approximately $23.8 million and
$12.0 million, respectively. At December 31, 1996, the State net operating
losses have been fully reserved for in the valuation allowance due to the
limited carryforward period allowed by the State of California. At December 31,
1996, Federal and State alternative minimum tax credit carryforwards were
approximately $6.7 million and $1.7 million, respectively.
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.
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 8.84% effective January 1, 1997.
The provision for income taxes for the years ended December 31, 1996, 1995
and 1994 consists of the following (in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Current:
Federal........................................ $5,671 $3,085 $ 96
State.......................................... 1,805 1,163 365
Deferred:
Federal........................................ 3,890 816 2,546
State.......................................... (801) (15) 547
Adjustment in state tax rate................ (769) -- --
Revision in prior years' tax estimates...... (732) -- --
Increase in valuation allowance............. -- -- 299
------ ------ ------
Total provision........................ $9,064 $5,049 $3,853
====== ====== ======
</TABLE>
The Company's effective rate for income taxes for the years ended December
31, 1996, 1995 and 1994 differs from the U.S. statutory rate, as reflected in
the following reconciliation.
<TABLE>
<CAPTION>
1996 1995 1994
----- ----- -----
<S> <C> <C> <C>
U.S. statutory tax rate............................. 35.0% 35.0% 35.0%
State income tax, net of Federal benefit............ 6.0 6.0 6.0
Depletion allowance................................. (2.3) (0.3) (8.6)
Effect of change in tax rates....................... (3.0) -- --
Revision in prior years' tax estimates.............. (2.6) -- --
Increase in valuation allowance..................... -- -- 7.8
Other, net.......................................... (0.4) (0.1) (1.2)
---- ---- ----
Effective income tax rate......................... 32.7% 40.6% 39.0%
==== ==== ====
</TABLE>
F-33
<PAGE> 80
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
22. 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 1996, 1995, and 1994 totaled $485,000, $350,000 and $311,000,
respectively.
23. PREFERRED STOCK
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
Company's initial public 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 offering by Electrowatt (see Note 24).
24. COMMON STOCK
In September 1996, Calpine completed the initial public offering of
18,045,000 shares of its common stock with $0.01 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 sold 12,567,180 shares of
common stock, representing its entire ownership interest in Calpine. As a result
of the Common Stock Offering, Electrowatt no longer owns any interest in
Calpine. 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. Approximately $13.0 million of total net proceeds was
used to repay short-term bank borrowings. The remaining net proceeds are for
working capital and general corporate purposes, and for the development and
acquisition of power generation facilities. 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 preferred stock into shares
of common stock.
25. STOCK-BASED COMPENSATION PROGRAMS
1996 Employee Stock Purchase Plan
The Company adopted 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. Shares are purchased
on February 28 and August 31 of each year. On the first purchase date of
February 28, 1997, employees purchased 25,819 shares of common stock at a
weighted average fair value of $13.60 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; such plan succeeded the Company's previously adopted stock option program.
The Company accounts for this plan under APB Opinion No. 25, under which no
compensation cost has been recognized in 1996. Had compensation cost for
F-34
<PAGE> 81
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
this plan been determined consistent with SFAS No. 123, Accounting for
Stock-Based Compensation, the Company's net income and earning per share would
have been reduced to the following pro forma amounts (in thousands, except per
share amounts):
<TABLE>
<CAPTION>
1996 1995
------- ------
<S> <C> <C> <C>
Net income.................................. As reported $18,692 $7,378
Pro forma $18,145 $7,232
Primary earnings per share.................. As reported $ 1.27 --
Pro forma $ 1.24 --
As adjusted primary earnings per share
assuming conversion of preferred stock.... As reported -- $ 0.52
Pro forma -- $ 0.51
</TABLE>
Because the SFAS No. 123 method 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 future years.
The Company may grant options for up to 4,041,858 shares under the SIP. As
of December 31, 1996, the Company had granted options to purchase 2,340,294
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.
A summary of the status of the Company's SIP at December 31, 1996 and
changes during the year then ended is presented in the table and narrative
below:
<TABLE>
<CAPTION>
SHARES OF COMMON STOCK
--------------------------- WEIGHTED
AVAILABLE SIP AVERAGE
FOR OPTION OPTION EXERCISE
OR AWARD SHARES PRICE
------------- --------- --------
<S> <C> <C> <C>
Balance, January 1, 1995.................. 1,160,782 1,436,141 $ 1.53
Granted................................. (444,333) 444,333 $ 4.91
Forfeited............................... 25,963 (25,963) $ 2.13
--------- -----
Balance, 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
Forfeited............................... 56,796 (56,796) $ 7.90
--------- -----
Balance, December 31, 1996................ 1,696,564 2,340,294 $ 3.69
========= =====
</TABLE>
F-35
<PAGE> 82
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes information concerning outstanding and
exercisable options at December 31, 1996:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING
--------------------------- OPTIONS EXERCISABLE
WEIGHTED ------------------------
AVERAGE WEIGHTED
REMAINING AVERAGE
EXERCISE NUMBER CONTRACTUAL NUMBER EXERCISE
PRICES OUTSTANDING LIFE EXERCISABLE PRICE
--------------------------------------- ----------- ----------- ----------- --------
<S> <C> <C> <C> <C>
$ 0.50................................. 934,920 6.00 934,920 $ 0.50
$ 1.85................................. 174,193 6.25 174,193 $ 1.85
$ 4.57................................. 296,058 7.75 222,043 $ 4.57
$ 4.91................................. 434,290 8.97 104,590 $ 4.91
$ 8.57................................. 490,833 10.00 -- $ 8.57
$16.00................................. 10,000 9.99 10,000 $16.00
--------- --------- -----
2,340,294 1,445,746 $ 1.71
========= ========= =====
</TABLE>
The estimated average fair value of options granted in 1995 and 1996 is
$1.23 and $3.29 on the date of grant using the Black-Scholes option pricing
model with the following weighted-average assumptions: risk-free interest rates
of 5.4% to 6.2%; expected dividend yields of zero percent; expected lives of 3
years; expected volatility of 0% to 27%.
26. RELATED PARTY TRANSACTIONS
In January 1995, the Company and Electrowatt entered into a management
services agreement whereby Electrowatt agreed to provide the Company with
advisory services in connection with the construction, financing, acquisition
and development of power projects, as well as any other advisory services as may
be required by the Company in connection with the operation of the Company.
Pursuant to this agreement, the Company paid $166,000 and $200,000 of such
management expenses in 1996 and 1995, respectively. The management services
agreement terminated September 25, 1996, with completion of the initial public
offering.
During 1996, 1995, and 1994, the Company paid $123,000, $106,000, and
$69,000, respectively, to Electrowatt pursuant to a guarantee fee agreement
whereby Electrowatt agreed to guarantee the payment, when due, of any and all
indebtedness of the Company to Credit Suisse in accordance with the terms and
conditions of the line of credit. Under the guarantee fee agreement, the Company
had agreed to pay to Electrowatt an annual fee equal to 1% of the average
outstanding balance of the Company's indebtedness to Credit Suisse during each
quarter as compensation for all services rendered under the guarantee fee
agreement. The guarantee fee agreement terminated in September 1996.
At December 31, 1996, the Company had approximately $1.2 million in
accounts receivable from Electrowatt (see Note 12) related to reimbursement of
costs for the sale of Electrowatt's common stock in Calpine. As a result of
Electrowatt's sale of Calpine common shares, Electrowatt no longer owns any
interest in Calpine.
F-36
<PAGE> 83
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
27. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from two
sources -- PG&E and SMUD. Revenues earned from these sources for the years ended
December 31, 1996, 1995 and 1994 were as follows (in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- -------
<S> <C> <C> <C>
PG&E........................................ $183,531 $112,522 $77,010
SMUD........................................ 14,609 12,345 9,296
Other....................................... 1,324 173 804
-------- -------- --------
199,464 125,040 87,110
Deferred revenues recognized (see Note 3)... -- 2,759 3,185
-------- -------- --------
Total electricity and steam sales........... $199,464 $127,799 $90,295
======== ======== ========
</TABLE>
PG&E, the Company's primary customer, is also affected by industry
restructuring and deregulation (see Note 28 regarding Regulation and CPUC
Restructuring).
28. COMMITMENTS AND CONTINGENCIES
Capital Projects -- The Company has 1997 commitments for capital
expenditures totaling $4.0 million related to various projects at its geothermal
facilities. In March 1996, the Company entered into an energy development
agreement with Phillips Petroleum Company to develop, construct, own and operate
a 240 megawatt gas-fired cogeneration facility at Phillips Houston Chemical
Complex in Pasadena, Texas. The Company commenced construction in February 1997,
with commercial operation scheduled to begin in October 1998. The Company has
1997 commitments of $97.2 million related to this 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.
The Company also has working interest agreements with third parties
providing for the sharing of approximately 25% to 30% of drilling and other well
costs, various percentages of other operating costs and 25% to 30% of revenues
on specified wells.
Expenses under these agreements for the years ended December 31, 1996, 1995
and 1994 are (in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
Production royalties.......................... $10,793 $10,574 $11,153
Lease payments................................ $ 246 $ 225 $ 252
</TABLE>
Natural Gas Purchases -- The Company enters into long-term gas purchase
contracts with third parties to supply gas to its gas-fired cogeneration
projects. Such contracts generally have terms of 1 to 24 months, and existing
contracts expire though July 31, 1997, continuing month to month thereafter
unless either party terminates the agreement upon sixty days written notice. On
January 31, 1997, the Company purchased MNI which supplies gas to the Greenleaf
Power Plants (see Note 5).
F-37
<PAGE> 84
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Watsonville Operating Lease -- The Company is committed under an operating
lease (through December 2009) for a 28.5 megawatt natural gas-fired cogeneration
power plant located in Watsonville, California (see Note 6). 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, 1996, future basic rent payments
are $2.9 million for each year from 1997 to 2001, and $24.4 million thereafter
through December 2009. Contingent rent payments are 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.
Office and Equipment Leases -- The Company leases its corporate office,
Houston office, Portland office, Santa Rosa office facilities and certain office
equipment under noncancellable operating leases expiring through 2001. Future
minimum lease payments under these leases are (in thousands):
<TABLE>
<S> <C>
1997................................................ $1,138
1998................................................ 1,125
1999................................................ 977
2000................................................ 936
2001................................................ 367
Thereafter.......................................... --
------
Total future minimum lease commitments.............. $4,543
======
</TABLE>
Lease payments are subject to adjustment for the Company's pro rata portion
of annual increases or decreases in building operating costs. In 1996, 1995 and
1994, rent expense for noncancellable operating leases amounted to $1,036,000,
$733,000 and $663,000, respectively.
Regulation and CPUC Restructuring -- Electricity and steam sales agreements
with PG&E are regulated by the CPUC. In December 1995, the CPUC proposed the
transition of the electric generation market to a competitive market beginning
January 1, 1998, with all consumers participating by 2003. Since the proposed
restructure results in widespread impact on the market structure and requires
participation and oversight of the Federal Energy Regulatory Commission
("FERC"), the CPUC has sought to build a California consensus involving the
legislature, the Governor, public and municipal utilities and customers. The
consensus has resulted in filings with FERC which should permit both the CPUC
and FERC to collectively proceed with implementation of the new competitive
market structure. On September 23, 1996 state legislation was passed, AB 1890
(the "Bill"), which codified much of the CPUC decision and directed the CPUC to
proceed with implementation of restructure no later than January 1, 1998. The
Bill accelerated the transition period to a fully competitive market from five
years to four years with all consumers participating by the year 2002. The Bill
provided for an electricity rate freeze for the period of transition and
mandated through issuance of rate reduction bonds a 10% rate reduction for small
commercial and residential customers effective January 1, 1998. The proposed
restructuring provides for phased-in customer choice (direct access),
development of a non-discriminatory market structure, full recovery of utility
stranded costs, sanctity of existing contracts, and continuation of existing
public policy programs including funds for enhancement of in-state renewable
energy technologies during the transition period. 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.
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 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
F-38
<PAGE> 85
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
"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 PSA, 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 -- The Company, together with over 100 other parties, was named
as a defendant in an action brought in August 1993 by the bankruptcy trustee for
Bonneville Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the
Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General
Corporation, et al., in the United States District Court for the District of
Utah (the "Court"). In December 1996, the trustee and the Company entered into a
settlement agreement relating to this matter. The trustee has agreed to waive
all claims against the Company and to dismiss the trustee's litigation against
the Company in exchange for a payment of $767,500 by the Company.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. Management does not expect that the
outcome of these cases will have a material adverse effect on the Company's
financial position or results of operations.
29. 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.
In the first quarter of 1996, the Company issued $50.0 million of preferred
stock to Electrowatt (see Note 23).
In the second quarter of 1996, the Company entered into an operating lease
for the King City Power Plant (see Note 9) and issued $180.0 million of 10 1/2%
Senior Notes Due 2006 (see Note 20).
In the third quarter of 1996, the Company acquired the Gilroy Power Plant
(see Note 10) and charged to earnings a $3.7 million uncollectible amount
associated with the attempt to acquire the O'Brien companies (see Note 13). The
Company also incurred an employee bonus expense of $1.4 million related to the
initial public offering of common stock in September 1996, and recorded a $1.8
million loss related to its electricity trading operations. In addition, the
Company decreased its deferred income taxes by $769,000 to reflect the change in
California's state income tax rate from 9.3% to 8.84% effective January 1, 1997.
In the fourth quarter of 1996, the Company recorded a $1.4 million net gain
related to the settlement of the Coso project, offset by a $767,500 expense
related to the settlement of certain litigation (see Note 28). In addition, the
Company revised its prior years' tax estimates by $700,000.
The Company's common stock has been traded on the New York stock exchange
beginning September 19, 1996. There were approximately 39 common stockholders of
record at December 31, 1996. No dividends have been paid to-date.
F-39
<PAGE> 86
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
QUARTER ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ ------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1996
Total revenue....................................... $61,663 $ 70,897 $50,321 $31,673
Income from operations.............................. $14,303 $ 29,097 $16,203 $ 7,188
Net income.......................................... $ 3,537 $ 10,732 $ 4,717 $ (294)
Earnings per common share........................... $ 0.17 $ 0.76 $ 0.35 $ (0.03)
Common stock price per share
High.............................................. $ 20.00 $ 16.38 -- --
Low............................................... $ 16.00 $ 16.00 -- --
1995
Total revenue....................................... $39,570 $ 42,176 $28,342 $22,010
Income from operations.............................. $11,473 $ 16,446 $ 8,195 $ 6,572
Net income.......................................... $ 2,115 $ 4,965 $ 239 $ 59
As adjusted earnings per common share assuming
conversion of preferred stock (see Note 2)........ $ 0.15 $ 0.35 $ 0.02 --
</TABLE>
F-40
<PAGE> 87
REPORT OF INDEPENDENT PUBLIC AUDITORS
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 March 7,
1997. 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
March 7 , 1997
F-41
<PAGE> 88
CALPINE CORPORATION
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
DECEMBER 31, 1996 AND 1995
<TABLE>
<CAPTION>
1996 1995
------------ ------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents..................................... $ 33,150,134 $ (1,970,526)
Accounts receivable........................................... 5,023,945 1,348,969
Accounts receivable from affiliates........................... 4,534,048 4,955,625
Acquisition project receivables............................... 791,206 8,805,186
Other current assets.......................................... 811,816 270,806
------------ ------------
Total current assets.................................. 44,311,149 13,410,060
Property, plant and equipment, net.............................. 5,711,074 724,359
Investments in power projects................................... 141,816,204 82,610,719
Intercompany receivables........................................ 302,230,313 48,323,629
Notes receivable from related parties........................... 18,182,372 19,390,952
Deferred charges................................................ 8,325,857 3,390,677
Other assets.................................................... 121,358 197,144
------------ ------------
Total assets.......................................... $520,698,327 $168,047,540
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.............................................. $ 503,598 $ 2,667,808
Accrued payroll and related expenses.......................... 3,477,246 2,582,194
Accrued interest payable...................................... 6,461,875 4,051,785
Other accrued expenses........................................ 5,385,747 2,704,257
------------ ------------
Total current liabilities............................. 15,828,466 12,006,044
Long-term line of credit........................................ -- 14,000,000
Senior Notes.................................................... 285,000,000 105,000,000
Deferred income taxes........................................... 11,229,502 7,877,537
Deferred revenue................................................ 5,513,458 3,937,175
------------ ------------
Total liabilities..................................... 317,571,426 142,820,756
------------ ------------
Stockholders' equity:
Common stock, $0.01 par value................................. 19,843 20,000
Additional paid-in capital.................................... 165,412,455 6,204,000
Retained earnings............................................. 37,694,603 19,002,784
------------ ------------
Total stockholders' equity............................ 203,126,901 25,226,784
------------ ------------
Total liabilities and stockholders' equity............ $520,698,327 $168,047,540
============ ============
</TABLE>
The accompanying notes are an integral part of these condensed financial
statements.
F-42
<PAGE> 89
CALPINE CORPORATION
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
<CAPTION>
1996 1995 1994
------------ ----------- -----------
<S> <C> <C> <C>
Revenue:
Service contract revenue from related parties.... $ 36,581,736 $28,733,399 $22,929,897
Income from unconsolidated investments in power
projects...................................... 66,625,486 32,397,392 23,711,895
------------ ----------- -----------
Total revenue................................. 103,207,222 61,130,791 46,641,792
Cost of revenue:
Service contract expenses........................ 34,953,440 27,433,069 19,161,445
------------ ----------- -----------
Gross profit....................................... 68,253,782 33,697,722 27,480,347
Project development expenses....................... 3,866,828 3,087,316 2,822,459
General and administrative expenses................ 13,650,881 8,081,458 6,867,520
------------ ----------- -----------
Income from operations........................ 50,736,073 22,528,948 17,790,368
Other (income) expense:
Interest expense................................. 23,036,232 10,479,144 9,207,381
Other income, net................................ (56,420) (377,276) (1,290,739)
------------ ----------- -----------
Income before provision for income taxes...... 27,756,261 12,427,080 9,873,726
Provision for income taxes......................... 9,064,445 5,049,568 3,853,115
------------ ----------- -----------
Net income.................................... $ 18,691,816 $ 7,377,512 $ 6,020,611
============ =========== ===========
Primary earnings per share
Weighted average number of shares outstanding.... 14,679,984 -- --
============ =========== ===========
Earnings per share............................... $ 1.27 -- --
============ =========== ===========
As adjusted primary earnings per share, assuming
Weighted average number of shares outstanding.... -- 14,150,837 --
============ =========== ===========
Earnings per share............................... -- $ 0.52 --
============ =========== ===========
</TABLE>
The accompanying notes are an integral part of these condensed financial
statements.
F-43
<PAGE> 90
CALPINE CORPORATION
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
<CAPTION>
1996 1995 1994
------------- ----------- ------------
<S> <C> <C> <C>
Net cash used in operating activities............ $(281,904,648) $(8,874,945) $(44,753,732)
------------- ------------ ------------
Cash flows from investing activities:
Acquisition of property, plant and equipment... (5,320,508) (367,711) (299,961)
Investments in power projects.................. -- (1,262,000) (175,352)
Decrease (increase) in notes receivable, net... 2,750,000 (10,336,640) 3,294,727
Other, net..................................... 75,786 (122,244) 97,838
------------- ------------ ------------
Net cash provided by (used in) investing
activities..................................... (2,494,722) (12,088,595) 2,917,252
------------- ------------ ------------
Cash flows from financing activities:
Payment of dividends........................... -- (800,000) (800,000)
Borrowings under line of credit................ 46,861,000 14,000,000 --
Repayment of borrowings under line of credit... (60,861,000) -- (52,595,000)
Proceeds from Senior Notes Due 2004............ -- -- 105,000,000
Proceeds from Senior Notes Due 2006............ 180,000,000 -- --
Proceeds from issuance of preferred stock...... 50,000,000 -- --
Proceeds from issuance of common stock......... 109,208,298 -- --
Costs associated with future financing......... (5,688,268) 279,012 (3,419,003)
Repayment of note payable to shareholder....... -- -- (1,200,000)
------------- ------------ ------------
Net cash provided by financing
activities........................... 319,520,030 13,479,012 46,985,997
------------- ------------ ------------
Net increase (decrease) in cash and cash
equivalents.................................... 35,120,660 (7,484,528) 5,149,517
Cash and cash equivalents, beginning of period... (1,970,526) 5,514,002 364,485
------------- ------------ ------------
Cash and cash equivalents, end of period......... $ 33,150,134 $(1,970,526) $ 5,514,002
============= ============ ============
Supplementary information:
Cash paid during the period for:
Interest....................................... $ 19,762,029 $ 9,945,443 $ 4,917,773
Income taxes................................... $ 6,947,000 $ 4,293,725 $ 683,364
</TABLE>
The accompanying notes are an integral part of these condensed financial
statements.
F-44
<PAGE> 91
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
DECEMBER 31, 1996
1. ORGANIZATION AND OPERATION OF CALPINE
Calpine Corporation ("Calpine") is a Delaware corporation 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 into 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. On September 13, 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.
2. LINES OF CREDIT AND REVOLVING CREDIT FACILITY
At December 31, 1996, Calpine had a $50.0 million three-year credit
facility available with a consortium of commercial lending institutions which
include The Bank of Nova Scotia, International Nederlanden U.S. Capital
Corporation, Sumitomo Bank of California and Canadian Imperial Bank of Commerce.
As of December 31, 1996, the Company had no borrowings and $5.9 million of
letters of credit outstanding, which reflect $3.0 million to secure performance
with the Pasadena Power Plant and $2.9 million related to operating expenses at
a subsidiary. Borrowings bear interest at The Bank of Nova Scotia's base rate or
at 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 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, 1995, Calpine had a $50.0 million credit facility with
Credit Suisse (whose parent company owns approximately 44.9% of Electrowatt Ltd.
("Electrowatt"), the former indirect sole owner of Calpine prior to the initial
public offering on September 25, 1996. At December 31, 1995, Calpine had $19.9
million of borrowings outstanding, bearing interest at LIBOR plus 0.5% (6.4% at
December 31, 1995). Interest was payable at either LIBOR or the Credit Suisse
base rate, plus applicable margins in both cases. The credit agreement specified
that Calpine maintain certain covenants with which Calpine was in compliance.
Calpine terminated its Credit Suisse credit facility on September 25, 1996.
At December 31, 1996, Calpine had one loan facility with available
borrowings totaling $1.2 million. There were no borrowings and 900,000 of
letters of credit outstanding as of December 31, 1996. At December 31, 1995,
Calpine had three loan facilities with available borrowings totaling $10.2
million. Borrowings and letters of credit outstanding were $1.2 million and $3.8
million as of December 31, 1995, respectively. Interest is payable at variable
interest rates based on bank base rates, LIBOR or prime plus applicable margins
in all cases (approximately 7.6% at December 31, 1995 on borrowings). The credit
agreements specified that Calpine maintain certain covenants with which Calpine
was in compliance.
3. NOTE PAYABLE TO ELECTROWATT
On December 31, 1991, Calpine declared a dividend of $1.2 million to its
parent company, Electrowatt Services, Inc. On the same date, Calpine issued a
note payable to Electrowatt Services, Inc. for $1.2 million.
F-45
<PAGE> 92
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
Interest was paid quarterly at a rate of 4.25%, which approximated market. The
note was paid on June 30, 1994, the maturity date.
4. SENIOR NOTES
On May 16, 1996, the Company issued $180.0 million aggregate principal
amount of 10 1/2% Senior Notes Due 2006. The net proceeds of $174.9 million were
used to repay $53.7 million of borrowings under the Credit Suisse Credit
Facility, $57.0 million of non-recourse project financing and $45.0 million of
borrowings from The Bank of Nova Scotia. The remaining $19.2 million was
available for general corporate purposes. Transaction costs of $5.1 million
incurred in connection with the public debt offering were recorded as a deferred
charge and are amortized over the ten-year life of the 10 1/2% Senior Notes Due
2006.
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 $191.7 million as of December 31,
1996.
On February 17, 1994, Calpine completed a $105.0 million public debt
offering of 9 1/4% Senior Notes Due 2004. Transaction costs of $4.1 million
incurred in connection with the public debt offering were recorded as a deferred
charge and are amortized over the ten-year life of the 9 1/4% Senior Notes Due
2004.
The 9 1/4% Senior Notes Due 2004 will mature on February 1, 2004. Calpine
has no sinking fund or mandatory redemption obligations with respect to the
9 1/4% Senior Notes Due 2006. 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 $105.7 million as of December 31,
1996.
The Senior Note indentures specify that Calpine maintain certain covenants
with which Calpine was in compliance. Calpine 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.
5. COMMITMENTS AND CONTINGENCIES
Capital Projects -- Calpine has 1997 commitments for capital expenditures
totaling $4.0 million related to various projects at its geothermal facilities.
In March 1996, Calpine entered into an energy development agreement with
Phillips Petroleum Company to develop, construct, own and operate a 240 megawatt
gas-fired cogeneration facility at Phillips Houston Chemical Complex in
Pasadena, Texas. The initial permitting process is underway, with construction
of the facility planned to begin in late 1996 and to be completed in 1998.
Calpine has 1997 commitments of $97.2 million related to this project.
Office and Equipment Leases -- Calpine leases its corporate office, Houston
office, Portland office, Santa Rosa office facilities and certain office
equipment under noncancellable operating leases expiring through 2001. Future
minimum lease payments under these leases are (in thousands):
<TABLE>
<S> <C>
1997.............................................. $1,138
1998.............................................. 1,125
1999.............................................. 977
2000.............................................. 936
2001.............................................. 367
Thereafter........................................ --
------
Total future minimum lease commitments............ $4,543
======
</TABLE>
F-46
<PAGE> 93
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
Lease payments are subject to adjustment for Calpine's pro rata portion of
annual increases or decreases in building operating costs. In 1996, 1995 and
1994, rent expense for noncancellable operating leases amounted to $1,036,000,
$733,000 and $663,000, 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 proposed the transition of the electric generation
market to a competitive market beginning January 1, 1998, with all consumers
participating by 2003. Since the proposed restructure results in widespread
impact on the market structure and requires participation and oversight of the
Federal Energy Regulatory Commission ("FERC"), the CPUC has sought to build a
California consensus involving the legislature, the Governor, public and
municipal utilities and customers. The consensus has resulted in filings with
FERC which should permit both the CPUC and FERC to collectively proceed with
implementation of the new competitive market structure. On September 23, 1996
state legislation was passed, AB 1890 ("the Bill"), which codified much of the
CPUC decision and directed the CPUC to proceed with implementation of
restructure no later than January 1, 1998. The Bill accelerated the transition
period to a fully competitive market from five years to four years with all
consumers participating by year 2002. The Bill provided for an electricity rate
freeze for the period of transition and mandated through issuance of rate
reduction bonds a 10% rate reduction for small commercial and residential
customers effective January 1, 1998. The proposed restructuring provides for
phased-in customer choice (direct access), development of a non-discriminatory
market structure, full recovery of utility stranded costs, sanctity of existing
contracts, and continuation of existing public policy programs including funds
for enhancement of in-state renewable energy technologies during the transition
period. Calpine cannot predict the final form or timing of the proposed
restructuring and the impact, if any, that such restructuring would have on
Calpine's existing business or results of operations. Calpine 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.
A domestic electricity generating project must be a qualified 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 ("PUHPA"), 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
PSA, 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 -- Calpine, together with over 100 other parties, was named as a
defendant in an action brought in August 1993 by the bankruptcy trustee for
Bonneville Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the
Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General
Corporation, et al., in the United States District Court for the District of
Utah (the "Court"). In December 1996, the trustee and Calpine entered into a
settlement agreement relating to this matter. The trustee has agreed to waive
all claims against Calpine and to dismiss the trustee's litigation against
Calpine in exchange for a payment of $767,500 by Calpine.
Calpine is involved in various other claims and legal actions arising out
of the normal course of business. Management does not expect that the outcome of
these cases will have a material adverse effect on Calpine's financial position
or results of operations.
F-47
<PAGE> 94
CALPINE CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
SCHEDULE II
(IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31, 1996
<TABLE>
<CAPTION>
ADDITIONS
-------------------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF 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 COSTS AND OTHER END OF
DESCRIPTION OF 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, 1994
<TABLE>
<CAPTION>
ADDITIONS
-------------------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- -------------------------------------------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserve for capitalized costs............... $ 800 $1,038 $ -- $ -- $1,838(1)
Allowance for uncollectible accounts........ $ -- 238 -- -- $ 238
====== ====== ====== ====== ======
</TABLE>
- ---------------
(1) Provision for write-off of project development expenses.
F-48
<PAGE> 95
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, 1996 and 1995, and
the related consolidated statements of income, changes in partners' equity, and
cash flows for each of the three years ended December 31, 1996. 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, 1996 and 1995, and
the results of their operations and cash flows for each of the three years ended
December 31, 1996, in conformity with generally accepted accounting principles.
MOSS ADAMS LLP
Everett, Washington
January 24, 1997
F-49
<PAGE> 96
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1996 1995
------------ ------------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents................................... $ 317,196 $ 199,169
Current portion of restricted cash and cash equivalents..... 5,787,121 2,937,884
Accounts receivable......................................... 4,605,135 3,090,213
Prepaid expenses............................................ 220,130 222,828
------------ ------------
Total current assets................................ 10,929,582 6,450,094
Restricted cash and cash equivalents, net of current
portion..................................................... 15,666,647 8,017,758
Property, plant and equipment, at cost, net................... 91,737,933 95,589,737
Other assets.................................................. 10,938,732 12,744,480
------------ ------------
Total assets........................................ $129,272,894 $122,802,069
============ ============
LIABILITIES AND PARTNERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities.................... $ 2,988,207 $ 2,051,178
Related party distributions and payables
Calpine Corporation payable.............................. 476,390 4,864
National Energy Systems Company payable.................. 1,490 1,861
Whatcom Cogeneration Partners, L.P. distribution......... 3,517,491 --
Current portion of long-term debt........................... 3,600,000 2,000,000
------------ ------------
Total current liabilities........................... 10,583,578 4,057,903
Related party payable -- Calpine Corporation, net of current
portion..................................................... -- 908,679
Long-term debt, net of current portion........................ 113,400,003 117,000,003
Future removal and site restoration costs..................... 679,600 502,600
Deferred income taxes......................................... 988,400 907,800
Commitments................................................... -- --
Partners' equity (deficit).................................... 3,621,313 (574,916)
------------ ------------
Total liabilities and partners' equity.............. $129,272,894 $122,802,069
============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-50
<PAGE> 97
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1996 1995 1994
------------ ------------ ------------
<S> <C> <C> <C>
Revenues
Power sales.................................... $ 43,488,465 $ 30,603,018 $ 29,206,469
Natural gas sales, net......................... 434,611 893,690 2,832,668
Other.......................................... 169,146 29,146 20,490
------------ ------------ ------------
Total revenues......................... 44,092,222 31,525,854 32,059,627
------------ ------------ ------------
Costs and expenses
Operating and production costs................. 16,852,253 18,493,245 19,032,754
Depletion, depreciation and amortization....... 5,702,310 6,965,496 6,715,156
General and administrative..................... 2,481,470 1,400,129 1,412,326
------------ ------------ ------------
Total costs and expenses............... 25,036,033 26,858,870 27,160,236
------------ ------------ ------------
Income from operations........................... 19,056,189 4,666,984 4,899,391
------------ ------------ ------------
Other income (expense)
Interest income................................ 406,537 490,071 436,741
Interest expense............................... (10,678,618) (11,006,056) (10,172,959)
Other expense.................................. (133,958) (60,664) (359,000)
------------ ------------ ------------
Total other expense.................... (10,406,039) (10,576,649) (10,095,218)
------------ ------------ ------------
Income (loss) before provision for income
taxes.......................................... 8,650,150 (5,909,665) (5,195,827)
Provision for income taxes....................... (155,951) (188,387) (581,190)
------------ ------------ ------------
Net income (loss)...................... $ 8,494,199 $ (6,098,052) $ (5,777,017)
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-51
<PAGE> 98
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
<S> <C>
Partners' Equity, December 31, 1993........................................... $11,300,153
Net loss...................................................................... (5,777,017)
-----------
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
===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-52
<PAGE> 99
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1996 1995 1994
------------ ----------- -----------
<S> <C> <C> <C>
Cash flows from operating activities
Net income (loss)................................ $ 8,494,199 $(6,098,052) $(5,777,017)
Adjustments to reconcile net income (loss) to net
cash from operating activities
Depletion, depreciation and amortization...... 6,571,522 6,965,496 6,715,156
Deferred income taxes......................... 80,600 134,000 532,400
Change in operating assets and liabilities
Accounts receivable......................... (1,514,922) 1,017,993 (1,254,639)
Prepaid expenses............................ 2,698 9,497 (30,342)
Accounts payable and accrued liabilities.... 1,114,029 (1,407,621) 1,081,431
Related party distributions and payables.... (437,524) 425,479 132,296
------------ ----------- -----------
Net cash from operating activities....... 14,310,602 1,046,792 1,399,285
------------ ----------- -----------
Cash flows from investing activities
Decrease (increase) in restricted cash and cash
equivalents................................... (10,498,126) 2,908,466 2,922,819
Acquisition of property, plant and equipment..... (913,970) (3,710,025) (3,690,399)
Other assets..................................... -- -- (167,483)
------------ ----------- -----------
Net cash from investing activities....... (11,412,096) (801,559) (935,063)
------------ ----------- -----------
Cash flows from financing activities
Repayment of long-term debt...................... (2,000,000) (400,000) (400,025)
Distributions to partners........................ (780,479) -- --
------------ ----------- -----------
Net cash from financing activities....... (2,780,479) (400,000) (400,025)
------------ ----------- -----------
Net increase (decrease) in cash and cash
equivalents...................................... 118,027 (154,767) 64,197
Cash and cash equivalents, beginning of year....... 199,169 353,936 289,739
------------ ----------- -----------
Cash and cash equivalents, end of year............. $ 317,196 $ 199,169 $ 353,936
============ =========== ===========
Supplementary disclosure of cash flow information
Cash paid for interest during the year........... $ 10,678,618 $11,006,056 $10,172,959
============ =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-53
<PAGE> 100
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) GENERAL -- Sumas Cogeneration Company, L.P. (the Partnership) is a
Delaware limited partnership formed on August 28, 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. The Partnership agreement specifies that certain preferential
distributions are paid to SEI and Whatcom. 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 has acquired and is operating and developing a portfolio of proven
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
incidental 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 Power & Light Company (Puget) under a 20-year electricity sales contract.
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 megawatt hours of electricity to
Puget as follows:
<TABLE>
<CAPTION>
MEGAWATT
YEAR ENDED DECEMBER 31, HOURS REVENUE
---------------------------------------------------- --------- -----------
<S> <C> <C>
1996................................................ 1,031,900 $43,488,000
1995................................................ 1,026,000 $30,603,000
1994................................................ 1,000,400 $29,206,000
</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 (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.
(b) 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. SEI and Whatcom are both currently entitled to a 50%
interest in the profits and losses of the Partnership, after the payment of
certain preferential distributions to Whatcom of approximately $2,756,000 and
$6,239,000 at December 31, 1996 and 1995, respectively, and to SEI of
approximately $536,000 and $441,000 at December 31, 1996 and 1995, respectively.
A portion of these preferential distributions compound at 20% per annum. After
Whatcom has received cumulative distributions representing a fixed
rate-of-return of 24.5% on its equity investment, exclusive of the preferential
distributions referred to above, SEI's share of operating distributions will
increase to 88.67% and Whatcom's share of operating distributions will decrease
to 11.33%.
F-54
<PAGE> 101
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(c) 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,
1996, distributions totaling $4,297,970 were paid or accrued. As of January 31,
1997, the accrued balance of $3,517,491 of distributions were paid. No
distributions were paid or accrued for the years ended December 31, 1995 and
1994.
(d) REVENUE RECOGNITION -- Revenue from the sale of electricity is
recognized based on kilowatt hours generated and delivered to Puget at
contractual rates. 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.
(e) 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 method include estimated
future costs of dismantlement and abandonments of $3,718,000 in 1996, $3,748,000
in 1995 and $3,630,000 in 1994. 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
$177,000 in 1996, $193,000 in 1995 and $169,000 in 1994 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%.
(f) JOINT VENTURE ACCOUNTING -- Substantially all 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.
(g) 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.
(h) 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,
excluding restricted cash and cash equivalents.
(i) 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
F-55
<PAGE> 102
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
(j) 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.
(k) 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.................................. 15 years
Gas contract costs............................... 20 years
</TABLE>
(l) INCOME TAXES -- Profits or losses of the Partnership are passed
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.
(m) 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.
NOTE 2 -- PROPERTY, PLANT AND EQUIPMENT
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1996 1995
------------ ------------
<S> <C> <C>
Land and land improvements...................... $ 381,071 $ 381,071
Plant and equipment............................. 84,152,257 84,061,359
Acquisition of gas properties, including
development thereon........................... 25,838,035 25,030,165
Furniture and fixtures.......................... 211,116 195,914
------------ ------------
110,582,479 109,668,509
Less accumulated depreciation and depletion..... 18,844,546 14,078,772
------------ ------------
$ 91,737,933 $ 95,589,737
============ ============
</TABLE>
Depreciation expense was $3,159,774 in 1996, $3,316,748 in 1995 and
$3,069,446 in 1994. Depletion expense was $1,606,000 in 1996, $1,843,000 in 1995
and $1,671,000 in 1994.
F-56
<PAGE> 103
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3 -- OTHER ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1996 1995
----------- -----------
<S> <C> <C>
Organization, start-up and development costs...... $ 4,844,015 $ 6,165,574
Financing costs................................... 3,909,886 4,254,719
Gas contract costs................................ 2,184,831 2,324,187
----------- -----------
$10,938,732 $12,744,480
=========== ===========
</TABLE>
NOTE 4 -- LONG-TERM DEBT
The Partnership and ENCO have loan agreements with The Prudential Insurance
Company of America (Prudential) and Credit Suisse (collectively, the Lenders).
Through September 1996, Credit Suisse was an affiliate of Whatcom. At December
31, 1996 and 1995, amounts outstanding under the term loan agreements, by
entity, were as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1996 1995
------------ ------------
<S> <C> <C>
Sumas Cogeneration Company, L.P................. $ 92,781,003 $ 94,367,003
ENCO Gas, Ltd................................... 24,219,000 24,633,000
------------ ------------
117,000,003 119,000,003
Less current portion............................ 3,600,000 2,000,000
------------ ------------
$113,400,003 $117,000,003
============ ============
</TABLE>
Scheduled annual principal payments under the loan agreements as of
December 31, 1996 are as follows:
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, AMOUNT
--------------------------------------------------------------- ------------
<S> <C>
1997........................................................... $ 3,600,000
1998........................................................... 4,200,000
1999........................................................... 5,400,000
2000........................................................... 7,200,000
2001........................................................... 10,800,000
Thereafter..................................................... 85,800,003
------------
$117,000,003
============
</TABLE>
The Partnership's loan is 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 quarterly 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 2.25% to .875%
as stated in the loan agreement. During the year ended December 31, 1996,
interest rates on the variable rate loan ranged from 6.94% to 7.38%. The loans
mature in May 2008.
ENCO's loan is 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 quarterly at either the LIBOR,
certificate of deposit rate or Credit Suisse's base rate, plus an applicable
margin as stated in the loan agreement. During the year ended December 31, 1996,
interest rates on the variable rate loan ranged from 6.94% to 7.38%. The loans
mature in May 2008.
F-57
<PAGE> 104
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Partnership pays Prudential an agency fee of $50,000 per year, adjusted
annually by an inflation index, 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.
NOTE 5 -- INCOME TAXES
The provision for income taxes represents Canadian taxes which consist of
the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Current
Federal large corporation tax.................... $ 41,340 $ 34,625 $ 31,314
British Columbia capital taxes................... 34,011 19,762 17,476
-------- -------- --------
75,351 54,387 48,790
Deferred........................................... 79,744 135,400 178,400
-------- -------- --------
155,095 189,787 227,190
Utilization of loss carryforwards for Canadian
income tax purposes.............................. -- 47,700 259,000
Reduction of (increase in) Canadian loss
carryforwards due to foreign exchange and other
adjustments...................................... 856 (49,100) 95,000
-------- -------- --------
$155,951 $188,387 $581,190
======== ======== ========
</TABLE>
The principal sources of temporary differences resulting in deferred tax
assets and liabilities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1996 1995
---------- ----------
<S> <C> <C>
Deferred tax asset
Canadian net operating loss carryforwards......... $ (919,400) $ (840,900)
Deferred tax liabilities
Acquisition and development costs of gas deducted
for tax purposes in excess of amounts deducted
for financial reporting purposes............... 1,907,800 1,748,700
---------- ----------
Net deferred tax liability..................... $ 988,400 $ 907,800
========== ==========
</TABLE>
F-58
<PAGE> 105
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The provision for income taxes differs from the Canadian statutory rate
principally due to the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Canadian statutory rate............................ 44.62% 44.62% 44.34%
Income taxes based on statutory rate............... $(45,824) $(33,852) $ 82,909
Capital taxes, net of deductible portion........... 60,175 47,028 36,678
Non-deductible provincial royalties, net of
resource allowance............................... 123,464 95,671 39,836
Depletion on gas properties with no tax basis...... 36,488 44,641 38,420
Foreign exchange adjustments....................... 16,362 14,860 29,347
Other.............................................. (35,570) 21,439 --
-------- -------- --------
$155,095 $189,787 $227,190
======== ======== ========
</TABLE>
As of December 31, 1996, ENCO has non-capital loss carryforwards of
approximately $2,061,000, which may be applied against taxable income of future
periods which expire as follows:
<TABLE>
<S> <C>
1999............................................. $1,619,000
2000............................................. $ 260,000
2003............................................. $ 182,000
</TABLE>
NOTE 6 -- RELATED PARTY TRANSACTIONS AND COMMITMENTS
(a) 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 $311,000 in 1996, $258,000 in 1995 and
$253,000 in 1994 was paid to SEI under this agreement.
(b) 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 anniversary of the Project completion date,
subject to renewal terms. Approximately $2,014,000 in 1996, $2,031,000 in 1995
and $1,946,000 in 1994 was earned under this agreement.
(c) 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, $19,000 in 1995 and $61,000 in 1994.
(d) 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 $107,000 in 1996, $100,000 in 1995 and
$101,000 in 1994 was paid under this agreement.
F-59
<PAGE> 106
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(e) 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 gas supply agreements with Westcoast Gas Services, Inc.
(WGSI) to provide the Partnership with quantities of firm gas. Commencing April
1, 1993, WGSI must provide the Partnership with quantities of gas ranging from
10,000 MMBtu's per day up to 12,900 MMBtu's per day at a firm price, as provided
under the agreements. Deliveries under the agreement are expected to terminate
on October 31, 1997.
The Partnership and ENCO have a gas management agreement with WGSI. WGSI is
paid a gas management fee for each MMBtu of gas delivered. 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.
ENCO is committed to the utilization of pipeline capacity on the Westcoast
Energy Inc. System. These firm capacity commitments are predominantly under
one-year renewable contracts. Firm capacity has been accepted at an annual cost
of approximately $3,526,000 in 1996, $2,569,000 in 1995 and $2,776,000 in 1994.
As collateral for the obligations of the Company under the gas supply and
gas management agreements with WGSI, the Partnership secured an irrevocable
standby letter of credit with Credit Suisse in favor of WGSI. In January 1996,
the face amount of the letter of credit was reduced, in accordance with its
terms, from $2,500,000 to $500,000. Accordingly, the required balance in the
cash collateral account supporting the letter of credit was reduced from
$2,500,000 to $500,000. As of December 31, 1996, the letter of credit had a face
amount of $500,000 and the Partnership had a restricted cash deposit of
$500,000. As of December 31, 1995, the letter of credit had a face amount of
$2,500,000 and the Partnership had a restricted cash deposit of $2,500,000.
(f) UTILITY SERVICES -- The Partnership entered into an agreement for
utility services with the City of Sumas, Washington. The City of Sumas has
agreed to provide a guaranteed annual 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.
The Partnership entered into 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 received a permit for waste water disposal from the
Washington State Department of Ecology which expires June 30, 2000.
(g) 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 $56,600 in 1996 and $48,400 in 1995
and 1994.
In April 1992, ENCO signed an operating lease for office space which
expires in March 1997. Monthly rental expense is approximately $1,700. Rental
expense was approximately $20,400 in 1996, $17,700 in 1995 and $17,000 in 1994.
F-60
<PAGE> 107
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Future minimum land and office lease commitments as of December 31, 1996
are as follows:
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, AMOUNT
----------------------------------------------------------------- ----------
<S> <C>
1997............................................................. $ 51,000
1998............................................................. 49,300
1999............................................................. 49,300
2000............................................................. 52,500
2001............................................................. 55,700
Thereafter....................................................... 812,600
----------
$1,070,400
==========
</TABLE>
(h) PARTNER LOAN -- In March 1994, the sole shareholder of SEI borrowed
$10,000,000 from Calpine. The loan bears interest at 16.25%, compounded
quarterly, and is collateralized by a subordinated assignment in SEI's interest
in the Partnership and a subordinated pledge of SEI's stock. The loan requires
payments of interest and principal to be made from 50% of SEI's cash
distributions from the Partnership, less amounts due to Whatcom under a previous
note. On March 15, 2004, all unpaid principal and interest on the loan is due.
NOTE 7 -- FAIR VALUES OF FINANCIAL INSTRUMENTS
The carrying amount of all cash and cash equivalents 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 long-term debt
with a carrying amount of $117,000,003 and $119,000,003 at December 31, 1996 and
1995, 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-61
<PAGE> 108
EXHIBIT 11
CALPINE CORPORATION AND SUBSIDIARIES
CALCULATION OF EARNINGS PER SHARE
(AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
FOR YEAR ENDING
DECEMBER 31,
-------------------
1996 1995
------- -------
<S> <C> <C>
Net income............................................................... $18,692 $ 7,378
======= =======
Primary earnings per share
Average number of common shares outstanding............................ 12,293
Conversion of preferred stock.......................................... 1,700
Common shares issuable upon exercise of stock options using the
treasury method..................................................... 687
-------
14,680
-------
Primary earnings per share.......................................... $ 1.27
=======
Fully diluted earnings per share
Average number of common shares outstanding............................ 12,293
Conversion of preferred stock.......................................... 1,700
Common shares issuable upon exercise of stock options using the
treasury method..................................................... 1,137
-------
15,130
-------
Fully diluted earnings per share.................................... $ 1.24
=======
As adjusted primary earnings per share assuming conversion of preferred
stock
Average number of common shares outstanding............................ 10,388
Assumed conversion of preferred stock.................................. 2,179
Common shares issuable upon exercise of stock options using the
treasury method..................................................... 1,584
-------
14,151
-------
As adjusted primary earnings per share.............................. $ 0.52
=======
</TABLE>
<PAGE> 109
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- --------------------------------------------------------------------------------
<C> <S>
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.
10.3.11 Amended and Restated Energy Sales Agreement, dated December 16, 1996, between
Phillips Petroleum Company and Pasadena Cogeneration, L.P.
27 Financial Data Schedule
</TABLE>
<PAGE> 1
EXHIBIT 10.1.17
================================================================================
CREDIT AGREEMENT
among
PASADENA COGENERATION L.P.,
a Delaware limited partnership
(Borrower)
and
ING (U.S.) CAPITAL CORPORATION
(Agent for the Banks)
and
THE BANKS PARTIES HERETO
_________________________________
240 MW Cogeneration Facility
Pasadena, Texas
==============================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
ARTICLE 1 - DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.1 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2 Rules of Interpretation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
ARTICLE 2 - THE CREDIT FACILITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2.1 Loan Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2.1.1 Construction Loan Facility . . . . . . . . . . . . . . . . . . . . . . . . . 1
2.1.2 Term Loan Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2.1.3 Interest Provisions Relating to All Loans . . . . . . . . . . . . . . . . . 4
2.1.4 Promissory Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
2.1.5 Loan Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2.1.6 Conversion of Loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
2.1.7 Prepayments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
2.2 Total Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.2.1 Loan Commitment Amounts . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.2.2 Reductions and Cancellations . . . . . . . . . . . . . . . . . . . . . . . . 8
2.3 Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.3.1 Advisory Fee; Syndication Fee . . . . . . . . . . . . . . . . . . . . . . . 9
2.3.2 Annual Agency Fee . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.3.3 Loan Commitment Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.4 Other Payment Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.4.1 Place and Manner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.4.2 Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.4.3 Late Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.4.4 Net of Taxes, Etc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
2.4.5 Application of Payments . . . . . . . . . . . . . . . . . . . . . . . . . . 11
2.4.6 Failure to Pay Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
2.4.7 Withholding Exemption Certificates . . . . . . . . . . . . . . . . . . . . . 12
2.5 Pro Rata Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
2.5.1 Borrowings, Commitment Reductions, Etc. . . . . . . . . . . . . . . . . . . 12
2.5.2 Sharing of Payments, Etc. . . . . . . . . . . . . . . . . . . . . . . . . . 13
2.6 Change of Circumstances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
2.6.1 Inability to Determine Rates . . . . . . . . . . . . . . . . . . . . . . . . 13
2.6.2 Illegality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
2.6.3 Increased Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
2.6.4 Capital Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
2.6.5 Notice; Participating Banks' Rights . . . . . . . . . . . . . . . . . . . . 15
2.7 Funding Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
2.8 Alternate Office; Minimization of Costs . . . . . . . . . . . . . . . . . . . . . . 15
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ARTICLE 3 - CONDITIONS PRECEDENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
3.1 Conditions Precedent to the Closing Date . . . . . . . . . . . . . . . . . . . . . 16
3.1.1 Resolutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
3.1.2 Incumbency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
3.1.3 Formation Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
3.1.4 Good Standing Certificates . . . . . . . . . . . . . . . . . . . . . . . . . 17
3.1.5 Satisfactory Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . 17
3.1.6 Operative Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
3.1.7 Certificate of Borrower . . . . . . . . . . . . . . . . . . . . . . . . . . 18
3.1.8 Legal Opinions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
3.1.9 Certificate of Insurance Consultant . . . . . . . . . . . . . . . . . . . . 18
3.1.10 Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
3.1.11 Certificate of the Independent Engineer . . . . . . . . . . . . . . . . . . 18
3.1.12 Reports of the Borrower's Environmental Consultant . . . . . . . . . . . . . 18
3.1.13 Certificate of the Fuel Consultant . . . . . . . . . . . . . . . . . . . . . 18
3.1.14 Certificate of Power Marketing Consultant . . . . . . . . . . . . . . . . . 18
3.1.15 Power Marketing Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
3.1.16 Schedule of Applicable Permits and Applicable Third Party Permits . . . . . 19
3.1.17 No Change in Tax Laws . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
3.1.18 Absence of Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
3.1.19 Payment of Filing Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
3.1.20 Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
3.1.21 UCC Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
3.1.22 Project Budget . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
3.1.23 Base Case Project Projections . . . . . . . . . . . . . . . . . . . . . . . 20
3.1.24 No Material Adverse Change . . . . . . . . . . . . . . . . . . . . . . . . . 20
3.1.25 A.L.T.A. Surveys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
3.1.26 Title Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
3.1.27 Qualifying Facility Status . . . . . . . . . . . . . . . . . . . . . . . . . 21
3.1.28 Notice to Proceed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
3.1.29 Establishment of Accounts . . . . . . . . . . . . . . . . . . . . . . . . . 22
3.1.30 Representations and Warranties of Partners and Borrower . . . . . . . . . . 22
3.1.31 Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
3.1.32 Interest Rate Hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
3.1.33 Key Personnel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
3.1.34 Project Schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
3.1.35 Reports of Borrower's Tax Consultants . . . . . . . . . . . . . . . . . . . 22
3.1.36 Reports of Borrower's HCC Evaluation Consultant . . . . . . . . . . . . . . 22
3.1.37 Phillips Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
3.2 Conditions Precedent to Each Construction Credit Event . . . . . . . . . . . . . . 23
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3.2.1 Credit Event Conditions Satisfied . . . . . . . . . . . . . . . . . . . . . 23
3.2.2 Monthly Drawdown Frequency . . . . . . . . . . . . . . . . . . . . . . . . . 23
3.2.3 Notice of Borrowing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
3.2.4 Drawdown Certificate and Engineer's Certificate . . . . . . . . . . . . . . 23
3.2.5 Amount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
3.2.6 Title Policy Endorsement . . . . . . . . . . . . . . . . . . . . . . . . . . 23
3.2.7 Lien Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
3.2.8 Applicable Permits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
3.2.9 Equity Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
3.2.10 Additional Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . 24
3.2.11 Acceptable Work; No Liens . . . . . . . . . . . . . . . . . . . . . . . . . 24
3.2.12 Casualty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.2.13 Absence of Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.2.14 Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.2.15 Key Personnel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.3 Conditions Precedent to Term-Conversion . . . . . . . . . . . . . . . . . . . . . . 25
3.3.1 Payment of Obligations. . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.3.2 Final Drawing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.3.3 Certificates of Occupancy . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.3.4 Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.3.5 Equity Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.3.6 Annual Budget . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.3.7 Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.3.8 Reserve Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.4 Conditions Precedent to Each Credit Event . . . . . . . . . . . . . . . . . . . . . 27
3.4.1 Representations and Warranties True and Correct . . . . . . . . . . . . . . 27
3.4.2 No Event of Default or Inchoate Default . . . . . . . . . . . . . . . . . . 27
3.4.3 Operative Documents, Applicable Permits and Applicable
Third Party Permits in Effect . . . . . . . . . . . . . . . . . . . . . . . 27
3.4.4 No Material Adverse Effect . . . . . . . . . . . . . . . . . . . . . . . . . 27
3.5 Conditions Precedent to Initial Distribution . . . . . . . . . . . . . . . . . . . 27
3.5.1 Term-Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
3.5.2 Revised Base Case Projections . . . . . . . . . . . . . . . . . . . . . . . 27
3.5.3 Delivery of Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
3.5.4 Applicable Permits and Applicable Third Party Permits . . . . . . . . . . . 27
3.5.5 A.L.T.A. Surveys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
3.5.6 Term Loan Title Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
3.5.7 Power Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
3.6 No Approval of Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
3.7 Waiver of Funding; Adjustment of Drawdown Requests . . . . . . . . . . . . . . . . 29
ARTICLE 4 - REPRESENTATIONS AND WARRANTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
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4.1 Organization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4.2 Authorization; No Conflict . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
4.3 Enforceability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
4.4 Compliance with Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
4.5 Business, Debt, Contracts, Joint Ventures Etc. . . . . . . . . . . . . . . . . . . 30
4.6 Adverse Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
4.7 Investment Company Act, Etc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4.8 ERISA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4.9 Permits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
4.10 Qualifying Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
4.11 Hazardous Substance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
4.12 Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
4.13 Labor Disputes and Acts of God . . . . . . . . . . . . . . . . . . . . . . . . . . 33
4.14 Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
4.15 Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
4.16 Private Offering by Borrower . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
4.17 Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
4.18 Governmental Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
4.19 Regulation U, Etc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
4.20 Project Budget; Projections; Commercial Operation Date . . . . . . . . . . . . . . 34
4.21 Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
4.22 Existing Defaults . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
4.23 No Default . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
4.24 Offices, Location of Collateral . . . . . . . . . . . . . . . . . . . . . . . . . . 35
4.25 Title and Liens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
4.26 Trademarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
4.27 Collateral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
4.28 Sufficiency of Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . 36
4.29 Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
4.30 Roads/Transmission Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
4.31 Proper Subdivision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
4.32 Flood Zone Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
ARTICLE 5 - COVENANTS OF THE BORROWER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
5.1 Use of Proceeds and Project Revenues . . . . . . . . . . . . . . . . . . . . . . . 38
5.1.1 Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
5.1.2 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
5.2 Payment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
5.2.1 Credit Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
5.2.2 Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
5.3 Warranty of Title . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
5.4 Notices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
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5.5 Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
5.6 Books, Records, Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
5.7 Compliance with Laws, Instruments, Etc. . . . . . . . . . . . . . . . . . . . . . . 42
5.8 Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
5.9 Existence, Conduct of Business, Properties, Etc. . . . . . . . . . . . . . . . . . 43
5.10 Debt Service Coverage Ratios . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
5.11 Indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
5.12 Qualifying Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
5.13 Construction of Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
5.14 Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
5.15 Operation of Project and Annual Operating Budget . . . . . . . . . . . . . . . . . 47
5.16 Adjustments to Project Projections . . . . . . . . . . . . . . . . . . . . . . . . 48
5.17 Preservation of Rights; Further Assurances . . . . . . . . . . . . . . . . . . . . 50
5.18 Project Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
5.19 Maintenance of Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
5.20 Taxes, Other Government Charges and Utility Charges . . . . . . . . . . . . . . . . 53
5.21 Event of Eminent Domain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
5.22 Interest Rate Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
5.22.1 Interest Rate Agreements . . . . . . . . . . . . . . . . . . . . . . . . . 54
5.22.2 Hedge Breaking Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
5.22.3 Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
5.22.4 Bank Participation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
5.23 Alternative Thermal Host Action Plan . . . . . . . . . . . . . . . . . . . . . . . 55
5.24 Performance Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
5.25 Power Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
5.25.1 Replacement of Power Marketer . . . . . . . . . . . . . . . . . . . . . . . 55
5.25.2 Requests for Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . 56
5.25.3 Firm Sales to HL&P . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
5.25.4 Arrangements with Power Marketer . . . . . . . . . . . . . . . . . . . . . 56
5.26 Auxiliary Boilers Contractor . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
5.27 Construction Management Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
5.28 Operating Agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
5.29 Stand-Alone Easements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
5.30 Extension of Lease, Lease of Expansion Property . . . . . . . . . . . . . . . . . . 58
5.31 License from Port Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
5.32 Phillips License from Port Authority . . . . . . . . . . . . . . . . . . . . . . . 58
5.33 Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
5.34 Option Title Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
ARTICLE 6 - NEGATIVE COVENANTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
6.1 Contingent Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
6.2 Limitations on Liens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
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6.3 Indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
6.4 Sale or Lease of Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
6.5 Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
6.6 Distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
6.7 Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
6.8 Transactions With Affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
6.9 Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
6.10 ERISA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
6.11 Partnerships, etc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
6.12 Dissolution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
6.13 Amendments; Change Orders; Completion. . . . . . . . . . . . . . . . . . . . . . . 60
6.14 Compliance with Operative Documents . . . . . . . . . . . . . . . . . . . . . . . . 62
6.15 Name and Location; Fiscal Year . . . . . . . . . . . . . . . . . . . . . . . . . . 62
6.16 Use of Project Site . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
6.17 Assignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
6.18 Abandonment of Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
6.19 Hazardous Substance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
6.20 Additional Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
6.21 Project Budget Amendments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
ARTICLE 7 - APPLICATION OF FUNDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
7.1 Construction Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
7.1.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 66
7.1.2 Disbursements from Construction Account . . . . . . . . . . . . . . . . . . 66
7.1.3 Rights of Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67
7.1.4 Proceeds of the Final Drawing . . . . . . . . . . . . . . . . . . . . . . . 67
7.1.5 Disbursements Following Term-Conversion . . . . . . . . . . . . . . . . . . 68
7.2 Revenue Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
7.2.1 Establishment of Account; Priority of Payments . . . . . . . . . . . . . . . 68
7.2.2 O&M Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69
7.2.3 Subordinated Fuel Costs . . . . . . . . . . . . . . . . . . . . . . . . . . 70
7.2.4 Subordinated O&M Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 70
7.2.5 Mandatory Prepayment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
7.3 Major Maintenance Reserve Account . . . . . . . . . . . . . . . . . . . . . . . . . 71
7.3.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 71
7.3.2 Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
7.3.3 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
7.3.4 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
7.4 Emissions Offsets Reserve Account . . . . . . . . . . . . . . . . . . . . . . . . . 72
7.4.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 72
7.4.2 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
7.4.3 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
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7.4.4 Letters of Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
7.5 Fuel Supply Reserve Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
7.5.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 73
7.5.2 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
7.5.3 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
7.5.4 Letters of Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
7.6 Debt Service Reserve Account . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
7.6.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 74
7.6.2 Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
7.6.3 Replenishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 75
7.6.4 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
7.6.5 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
7.6.6 Letters of Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
7.7 Operating Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
7.7.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 76
7.7.2 Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
7.7.3 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
7.8 Loss Proceeds Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
7.9 Accrual Sub-Account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
7.9.1 Establishment of Sub-Account . . . . . . . . . . . . . . . . . . . . . . . . 76
7.9.2 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
7.9.3 Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
7.10 Distribution Suspense Account; Initial Distribution Suspense Account . . . . . . . 77
7.10.1 Establishment of Account . . . . . . . . . . . . . . . . . . . . . . . . . . 77
7.10.2 Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
7.10.3 Withdrawals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
7.11 Application of Insurance Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . 78
7.11.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78
7.11.2 Business Interruption Insurance . . . . . . . . . . . . . . . . . . . . . . 78
7.11.3 Applications; Mandatory Prepayments . . . . . . . . . . . . . . . . . . . . 78
7.11.4 Proceeds Less than $1,000,000 . . . . . . . . . . . . . . . . . . . . . . . 79
7.11.5 Proceeds in Excess of $1,000,000, Not in Excess of $5,000,000 . . . . . . . 79
7.11.6 Proceeds in Excess of $5,000,000 . . . . . . . . . . . . . . . . . . . . . . 79
7.11.7 Repair and Restoration Procedures . . . . . . . . . . . . . . . . . . . . . 80
7.11.8 Excess Insurance Proceeds . . . . . . . . . . . . . . . . . . . . . . . . . 80
7.11.9 Events of Default . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80
7.12 Application of Eminent Domain Proceeds . . . . . . . . . . . . . . . . . . . . . . 81
7.13 Application of Certain Damages Payments; Mandatory Prepayments . . . . . . . . . . 81
7.13.1 Contractor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81
7.13.3 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81
7.14 Security Interest in Proceeds and Accounts . . . . . . . . . . . . . . . . . . . . 81
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7.15 Permitted Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
7.16 Earnings on Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
7.17 Dominion and Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
7.18 Termination of Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
ARTICLE 8 - EVENTS OF DEFAULT; REMEDIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
8.1 Events of Default . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
8.1.1 Failure to Make Payments . . . . . . . . . . . . . . . . . . . . . . . . . . 82
8.1.2 Judgments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
8.1.3 Misstatements; Omissions . . . . . . . . . . . . . . . . . . . . . . . . . . 83
8.1.4 Bankruptcy; Insolvency . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
8.1.5 Debt Cross Default . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
8.1.6 ERISA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84
8.1.7 Breach of Project Documents . . . . . . . . . . . . . . . . . . . . . . . . . 84
(a) Borrower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84
(b) Third Party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
(c) Termination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
8.1.8 Breach of Terms of Agreement . . . . . . . . . . . . . . . . . . . . . . . . 85
8.1.9 Term-Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
8.1.10 Conditions to Initial Distributions . . . . . . . . . . . . . . . . . . . . 86
8.1.11 Loss of Qualifying Facility Status . . . . . . . . . . . . . . . . . . . . . 86
8.1.12 Abandonment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
8.1.13 Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
8.1.14 Loss of Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87
8.1.15 Loss of or Failure to Obtain Applicable Permits or
Applicable Third Party Permits . . . . . . . . . . . . . . . . . . . . . . 87
8.1.16 Loss of Collateral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
8.1.17 Material Adverse Effect . . . . . . . . . . . . . . . . . . . . . . . . . . 88
8.2 Remedies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
8.2.1 No Further Loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
8.2.2 Cure by Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88
8.2.3 Acceleration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
8.2.4 Cash Collateral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
8.2.5 Possession of Project . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
8.2.6 Remedies Under Credit Documents . . . . . . . . . . . . . . . . . . . . . . . 89
ARTICLE 9 - SCOPE OF LIABILITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
ARTICLE 10 - THE AGENT; SUBSTITUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90
10.1 Appointment, Powers and Immunities . . . . . . . . . . . . . . . . . . . . . . . . 90
10.2 Reliance by Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91
10.3 Non-Reliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91
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10.4 Defaults . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
10.5 Indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
10.6 Successor Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
10.7 Authorization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
10.8 Agent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
10.9 Amendments; Waivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
10.10 Withholding Tax . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
10.11 General Provisions as to Payments . . . . . . . . . . . .. . . . . . . . . . . . . 95
10.12 Substitution of Bank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
10.13 Participation . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . 95
10.14 Transfer of Commitment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96
10.15 Laws . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . 96
10.16 Assignability to Federal Reserve Bank . . . . . . . . . . . . . . . . . . . . . . 96
ARTICLE 11 - INDEPENDENT CONSULTANTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
11.1 Removal and Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
11.2 Duties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
11.3 Independent Consultants' Certificates . . . . . . . . . . . . . . . . . . . . . . . 97
11.4 Certification of Dates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
ARTICLE 12 - MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
12.1 Addresses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
12.2 Additional Security; Right to Set-Off . . . . . . . . . . . . . . . . . . . . . . . 99
12.3 Delay and Waiver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99
12.4 Costs, Expenses and Attorneys' Fees; Syndication . . . . . . . . . . . . . . . . . 99
12.5 Entire Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
12.6 Governing Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
12.7 Severability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
12.8 Headings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
12.9 Accounting Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
12.10 Additional Financing . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . 100
12.11 No Partnership, Etc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
12.12 Deed of Trust/Collateral Documents . . . . . . . . . . . . .. . . . . . . . . . . . 101
12.13 Limitation on Liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
12.14 Waiver of Jury Trial . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . 101
12.15 Consent to Jurisdiction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
12.16 Usury . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . 102
12.17 Knowledge and Attribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102
12.18 Successors and Assigns . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . 102
12.19 Counterparts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102
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<PAGE> 11
INDEX OF EXHIBITS
<TABLE>
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Exhibit A Definitions and Rules of Interpretation
NOTES
Exhibit B-1 Form of Construction Note
Exhibit B-2 Form of Term Note
LOAN DISBURSEMENT PROCEDURES
Exhibit C-1 Form of Notice of Borrowing
Exhibit C-2 Form of Notice of Term-Conversion
Exhibit C-3 Form of Confirmation of Interest Period Selection
Exhibit C-4 Form of Notice of Conversion of Loan Type
Exhibit C-5 Form of Drawdown Certificate
Exhibit C-6 Form of Engineer's Certificate
Exhibit C-7 Form of Disbursement Requisition
Exhibit C-8 Form of Reserve Account Disbursement Requisition
EQUITY AND SECURITY-RELATED DOCUMENTS
Exhibit D-1 Form of Depositary Agreement
Exhibit D-2A Form of Equity Commitment Guaranty
Exhibit D-2B Form of Contingent Equity Guaranty
Exhibit D-3 Form of Deed of Trust
Exhibit D-4 Form of Security Agreement
Exhibit D-5 Form of Partnership Interest Pledge and Security Agreement
Exhibit D-6 Form of Shareholder Pledge and Security Agreement
Exhibit D-7 Form of Plant Operator Subordination Agreement
Exhibit D-8 Form of Lien Subordination Agreement
Exhibit D-9 Form of Subordination Agreement (Subordinated Debt)
Exhibit D-10 Schedule of Permitted Encumbrances
Exhibit D-11 Schedule of Security Filings
CONSENTS
Exhibit E-1 Form of Consent for Contracting Party
Exhibit E-2 Schedule of Closing Date Consents
CLOSING CERTIFICATES
Exhibit F-1 Form of Borrower's Closing Certificate
Exhibit F-2 Form of Insurance Consultant's Certificate
Exhibit F-3 Form of Independent Engineer's Certificate
Exhibit F-4 Form of Fuel Consultant's Certificate
Exhibit F-5 Form of Power Marketing Consultant's Certificate
PROJECT DESCRIPTION EXHIBITS
Exhibit G-1 Description of Project
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Exhibit G-2 Power Marketing Plan
Exhibit G-3 Schedule of Applicable Permits
Exhibit G-4 Project Budget
Exhibit G-5 Base Case Project Projections
Exhibit G-6 Project Schedule
Exhibit G-7 Pending Litigation
Exhibit G-8 Hazardous Substances Disclosure
OTHER
Exhibit H Banks/Lending Offices
Exhibit I Amortization Schedule
Exhibit J-1 Form of Withholding Certificate (Treaty)
Exhibit J-2 Form of Withholding Certificate (Effectively Connected)
Exhibit K Insurance Requirements
Exhibit L Annual Insurance Consultant's Certificate
Exhibit M Dispute Resolution
</TABLE>
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<PAGE> 13
THIS CREDIT AGREEMENT (this "Agreement") dated as of
December 20, 1996, is entered into among PASADENA COGENERATION L.P., a Delaware
limited partnership, as Borrower, the financial institutions listed on Exhibit
H or who later become a party hereto (the "Banks") and ING (U.S.) CAPITAL
CORPORATION, as Agent for the Banks.
In consideration of the agreements herein and in the other
Credit Documents and in reliance upon the representations and warranties set
forth herein and therein, the parties agree as follows:
ARTICLE 1 - DEFINITIONS
1.1 Definitions. Except as otherwise expressly provided,
capitalized terms used in this Agreement and its exhibits shall have the
meanings given in Exhibit A.
1.2 Rules of Interpretation. Except as otherwise
expressly provided, the rules of interpretation set forth in Exhibit A shall
apply to this Agreement and the other Credit Documents.
ARTICLE 2 - THE CREDIT FACILITIES
2.1 Loan Facilities.
2.1.1 Construction Loan Facility.
(a) Availability. Subject to the terms
and conditions set forth in this Agreement, each Bank severally agrees to
advance to Borrower from time to time during the Construction Loan Availability
Period such loans as Borrower may request under this Section 2.1.1
(individually, a "Construction Loan" and collectively the "Construction
Loans"), in an aggregate principal amount not to exceed such Bank's
Construction Loan Commitment.
(b) Notice of Borrowing. Borrower shall
request Construction Loans by delivering to Agent a written notice in the form
of Exhibit C-1, appropriately completed (a "Notice of Borrowing"), which
specifies, among other things:
(i) The principal portion of the
requested Borrowing which will bear interest as provided in (1) Section
2.1.1(c)(i) (individually, a "Base Rate Construction Loan") and/or (2) Section
2.1.1(c)(ii) (individually, a "LIBOR Construction Loan");
(ii) The amount of the requested
Borrowing, which shall be in the minimum amount of $1,000,000 or an integral
multiple of $10,000 in excess thereof;
(iii) The date of the requested
Borrowing, which shall be a Banking Day; and
(iv) If the requested Borrowing is
to consist of LIBOR Construction Loans, the initial Interest Periods selected
by Borrower for such Loans.
<PAGE> 14
Borrower shall give each Notice of Borrowing relating to
Construction Loans to Agent so as to provide the Minimum Notice Period
applicable to Construction Loans of the Type requested. Any Notice of
Borrowing may be modified or revoked by Borrower through the Banking Day prior
to the Minimum Notice Period, and shall thereafter be irrevocable.
(c) Construction Loan Interest.
Borrower shall pay interest on the unpaid principal amount of each Construction
Loan from the date of such Construction Loan until the maturity or prepayment
thereof at the following rates per annum:
(i) With respect to the principal
portion of such Construction Loan which is, and during such periods as such
Construction Loan is, a Base Rate Construction Loan, at a rate per annum equal
to the Base Rate plus 0.750%, such rate to change from time to time as the Base
Rate shall change; and
(ii) With respect to the principal
portion of such Construction Loan which is, and during such portion of such
periods as such Construction Loan is, a LIBOR Construction Loan, at a rate per
annum, at all times during each Interest Period for such LIBOR Construction
Loan, equal to the LIBO Rate for such Interest Period plus 1.500%.
(d) Construction Loan Principal
Payments. Borrower shall repay to Agent, for the account of each Bank, in full
on the Construction Loan Maturity Date the unpaid principal amount of all
Construction Loans made by such Bank which will not be Term-Converted to Term
Loans as provided in Section 2.1.2(a). Upon payment or Term-Conversion, in
full, of the aggregate principal amount of the Construction Loans and all
accrued and unpaid interest thereon, the Banks shall promptly mark the
Construction Notes cancelled and return such cancelled Construction Notes to
Borrower.
2.1.2 Term Loan Facility.
(a) Availability. Subject to the terms
and conditions set forth in this Agreement, each Bank severally agrees to make
to Borrower on the date of Term-Conversion specified pursuant to Section
2.1.2(b)(iii), at the request of Borrower, a term loan under this Section 2.1.2
(individually a "Term Loan" and collectively the "Term Loans") in an aggregate
principal amount not to exceed such Bank's Term Loan Commitment. Each Bank
shall make its Term Loan by converting the portion of its outstanding
Construction Loans equal to such Bank's Term Loan Commitment to a Term Loan.
(b) Notice of Term-Conversion. Upon
satisfaction of the conditions set forth in Section 3.3, Borrower shall request
the Term-Conversion by delivering to Agent a written notice in the form of
Exhibit C-2, appropriately completed ("Notice of Term-Conversion"), which
specifies:
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<PAGE> 15
(i) The principal portion of the
Term Loans which will bear interest as provided in (1) Section 2.1.2(c)(i)(A)
(individually, a "Base Rate Term Loan") and/or (2) Section 2.1.2(c)(i)(B)
(individually, a "LIBOR Term Loan");
(ii) The aggregate amount of the
Term Loans, which shall not exceed the lesser of the Total Term Loan Commitment
and the aggregate principal amount of all Construction Loans outstanding on the
date of Term-Conversion (immediately prior to Term-Conversion, after giving
effect to the Final Drawing and the application of: (x) all Base Equity
pursuant to Section 5.18, (y) all liquidated damages required to be applied to
the prepayment of Construction Loans pursuant to Section 7.1.4 or 7.13, and (z)
any Base Equity or Additional Borrower Equity required to be applied to the
prepayment of Construction Loans pursuant to Section 5.18);
(iii) The proposed date of the
Term-Conversion, which shall be no later than the Construction Loan Maturity
Date; and
(iv) If the Term Loans are to
consist of LIBOR Loans, the initial Interest Periods selected by Borrower for
such Loans.
Borrower shall so deliver the Notice of Term-Conversion to Agent so as to
provide at least the Minimum Notice Period applicable to Loans of the Type
requested upon Term-Conversion. The Notice of Term-Conversion may be modified
or revoked by Borrower through the Banking Day prior to the Minimum Notice
Period, and thereafter shall be irrevocable.
(c) Term Loan Interest.
(i) Borrower shall pay interest on
the unpaid principal amount of each Term Loan from the date of such Term Loan
until the maturity or prepayment thereof at one of the following rates per
annum:
(A) With respect to the
principal portion of such Term Loan which is, and during such periods as such
Term Loan is, a Base Rate Term Loan, at a rate per annum equal to the Base Rate
plus the percentage listed below, such rate to change from time to time as the
Base Rate shall change:
<TABLE>
<S> <C>
First Term Period 0.500%
Second Term Period 0.750%
Third Term Period 1.125%
Fourth Term Period 1.750%
</TABLE>
(B) With respect to the
principal portion of such Term Loan which is, and during such periods as such
Term Loan is, a LIBOR Term Loan, at a rate per annum during each Interest Period
for such LIBOR Term Loan equal to the LIBO Rate for such Interest Period plus
the percentage listed below:
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<PAGE> 16
<TABLE>
<S> <C>
First Term Period 1.250%
Second Term Period 1.500%
Third Term Period 1.875%
Fourth Term Period 2.500%
</TABLE>
provided, however, that, in the case of clauses (A) and (B) above, (a) in the
event that and for so long as, from time to time, Borrower has met the
Extension Requirements on the last day of the last preceding calendar quarter,
then (i) the percentages set forth above for the Third Term Period and the
Fourth Term Period shall, from and after the day following the date of Term-
Conversion, be reduced by 0.250% and (ii) the percentage set forth above for
the Fourth Term Period shall, from and after the day following the tenth
anniversary of the date of Term-Conversion, be reduced by an additional 0.375%;
provided further, however, notwithstanding anything to the contrary in the
foregoing proviso, in the event that from time to time, the Four-Quarter
Average Debt Service Coverage Ratio calculated on the last day of the last
preceding calendar quarter is less than 1.50 to 1.00, then each of the
percentages set forth above shall not be decreased and instead shall be
increased by .250%, until such time as the Four- Quarter Average Debt Service
Coverage Ratio as of the end of any subsequent calendar quarter is equal to or
greater than 1.50 to 1.00 at which time the percentages set forth above shall
no longer be increased by such 0.250% and shall return to the percentages set
forth above (subject to increase or decrease pursuant to this Section
2.1.2(c)).
(d) Term Loan Principal Payment.
Borrower shall repay to Agent, for the account of each Bank, the aggregate
unpaid principal amount of the Term Loan made by such Bank in installments
payable on each Repayment Date in accordance with the repayment schedule set
forth on Exhibit I, with any remaining unpaid principal, interest, fees and
costs due and payable on the Term Loan Maturity Date.
2.1.3 Interest Provisions Relating to All Loans.
(a) Interest Payment Dates. Borrower
shall pay accrued interest on the unpaid principal amount of each Loan (i) in
the case of each Base Rate Loan, on the last Banking Day of each calendar
quarter, (ii) in the case of each LIBOR Loan, on the last day of each Interest
Period related to such LIBOR Loan and, if such Interest Period is longer than
three months, every three months after the date of such LIBOR Loan and (iii) in
all cases, upon prepayment (to the extent thereof and including any optional
prepayments or Mandatory Prepayments), upon conversion from one Type of Loan to
another Type, and at maturity (whether by acceleration or otherwise).
(b) LIBOR Loan Interest Periods.
(i) The initial and subsequent
Interest Period for LIBOR Loans shall be a maximum of one month during the six
month period immediately following the Closing Date; provided that Agent may
otherwise approve, in its sole discretion, a longer Interest Period which is
requested by Borrower and otherwise complies with the following provisions of
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<PAGE> 17
this Section 2.1.3(b)(i). Thereafter, each subsequent Interest Period
(including any Interest Period referenced in the proviso of the first sentence
of this Section 2.1.3(b) selected by Borrower for all LIBOR Loans shall be one,
two, three or six months or such other period as close to three months as is
practicable to enable Borrower to limit the number of LIBOR Loans as required
by this Section 2.1.3(b) or to comply with clauses (C), (D) or (E) of the next
sentence. Notwithstanding anything to the contrary in either of the two
preceding sentences, (A) any Interest Period which would otherwise end on a day
which is not a Banking Day shall be extended to the next succeeding Banking Day
unless such next Banking Day falls in another calendar month, in which case
such Interest Period shall end on the immediately preceding Banking Day; (B)
any Interest Period which begins on the last Banking Day of a calendar month
(or on a day for which there is no numerically corresponding day in the
calendar month at the end of such Interest Period) shall end on the last
Banking Day of a calendar month; (C) Borrower may not select Interest Periods
which would leave a greater principal amount of Loans subject to Interest
Periods ending after a date upon which Loans are or may be required to be
repaid (including the Construction Loan Maturity Date and each Repayment Date)
than principal amount of Loans scheduled to be outstanding after such date; (D)
unless Term-Conversion has occurred, any Interest Period for a Construction
Loan which would otherwise end after the Construction Loan Maturity Date shall
end on the Construction Loan Maturity Date; (E) any Interest Period for a Term
Loan which would otherwise end after the Term Loan Maturity Date shall end on
the Term Loan Maturity Date; (F) LIBOR Loans for each Interest Period shall be
in the amount of at least $100,000; and (G) Borrower may not at any time have
outstanding more than six different Interest Periods relating to LIBOR Loans.
(ii) Borrower may contact Agent
at any time prior to the end of an Interest Period, for a quotation of Interest
Rates in effect at such time for given Interest Periods and Agent shall promptly
provide such quotation. Borrower may select an Interest Period telephonically
within the time periods specified in Section 2.1.6, which selection shall be
irrevocable on and after the applicable Minimum Notice Period. Borrower shall
confirm such telephonic notice to Agent by telecopy on the day such notice is
given (in substantially the form of Exhibit C-3, a "Confirmation of Interest
Period Selection"). Borrower shall promptly deliver to Agent the original of the
Confirmation of Interest Period Selection initially delivered by telecopy. If
Borrower fails to notify Agent of the next Interest Period for any LIBOR Loans
in accordance with this Section 2.1.3(b), such Loans shall automatically convert
to Base Rate Loans on the last day of the current Interest Period therefor.
Agent shall as soon as practicable (and, in any case, within two Banking Days
after delivery of the Confirmation of Interest Period Selection) notify Borrower
of each determination of the Interest Rate applicable to each Loan.
(c) Interest Account and Interest
Computations. Borrower authorizes Agent to record in an account or accounts
maintained by Agent on its books (i) the interest rates applicable to all Loans
and the effective dates of all changes thereto, (ii) the Interest Period for
each LIBOR Loan, (iii) the date and amount of each principal and interest
payment on each Loan and (iv) such other information as Agent may determine is
necessary for the computation of interest payable by Borrower hereunder.
Borrower agrees that all computations by Agent of interest shall be conclusive
in the absence of manifest error. All computations of
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<PAGE> 18
interest on Base Rate Loans shall be based upon a year of 365 or 366 days and
the actual days elapsed, and shall be adjusted in accordance with any changes
in the Base Rate to take effect on the beginning of the day of such change in
the Base Rate. All computations of interest on LIBOR Loans shall be based upon
a year of 360 days and the actual days elapsed.
2.1.4 Promissory Notes. The obligation of Borrower
to repay the Loans made by each Bank and to pay interest thereon at the rates
provided herein shall be evidenced by promissory notes in the form of Exhibit
B-1 (individually, a "Construction Note") and Exhibit B-2 (individually, a
"Term Note"), each payable to the order of such Bank and in the principal
amount of such Bank's Construction Loan Commitment and Term Loan Commitment,
respectively. Borrower authorizes each Bank to record on the schedule annexed
to such Bank's Note or Notes, the date and amount of each Loan made by such
Bank, and each payment or prepayment of principal thereunder and agrees that
all such notations shall constitute prima facie evidence of the matters noted.
Borrower further authorizes each Bank to attach to and make a part of such
Bank's Note or Notes continuations of the schedule attached thereto as
necessary. No failure to make any such notations, nor any errors in making any
such notations, shall affect the validity of Borrower's obligations to repay
the full unpaid principal amount of the Loans or the duties of Borrower
hereunder or thereunder.
2.1.5 Loan Funding.
(a) Notice. Each Notice of Borrowing
shall be delivered to Agent in accordance with Section 12.1. Agent shall
promptly notify each Bank of the contents of each Notice of Borrowing.
(b) Pro Rata Loans. All Loans shall be
made on a pro rata basis by the Banks in accordance with their respective
Proportionate Shares of such Loans, with each Borrowing to consist of a Loan by
each Bank equal to such Bank's Proportionate Share of such Borrowing.
(c) Bank Funding. Each Bank shall,
before 12:00 noon on the date of each Borrowing, make available to Agent at its
office specified in Section 12.1, in same day funds, such Bank's Proportionate
Share of such Borrowing. The failure of any Bank to make the Loan to be made
by it as part of any Borrowing shall not relieve any other Bank of its
obligation hereunder to make its Loan on the date of such Borrowing. No Bank
shall be responsible for the failure of any other Bank to make the Loan to be
made by such other Bank on the date of any Borrowing.
(d) Construction Account. No later than
2:00 p.m. on the date specified in each Notice of Borrowing, if the applicable
conditions precedent listed in Article 3 have been satisfied and to the extent
Agent shall have received the appropriate funds from the Banks, Agent will make
available the Construction Loans requested in such Notice of Borrowing (or so
much thereof as the Banks shall have approved pursuant to this Agreement) in
Dollars and
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<PAGE> 19
in immediately available funds, at Agent's New York Branch, and shall deposit
such Construction Loans into the Construction Account.
2.1.6 Conversion of Loans. Borrower may convert
Loans from one Type of Loans to another Type; provided, however, that (i) any
conversion of LIBOR Loans into Base Rate Loans shall be made on, and only on,
the first day after the last day of an Interest Period for such LIBOR Loans and
(ii) Loans shall be converted only in amounts of $100,000 or more. Borrower
shall request such a conversion by a written notice to Agent in the form of
Exhibit C-4, appropriately completed (a "Notice of Conversion of Loan Type"),
which specifies:
(a) The Loans, or portion thereof, which
are to be converted;
(b) The Type into which such Loans, or
portion thereof, are to be converted;
(c) If such Loans are to be converted
into LIBOR Loans, the initial Interest Period selected by Borrower for such
Loans in accordance with Section 2.1.3(b); and
(d) The date of the requested
conversion, which shall be a Banking Day.
Borrower shall so deliver each Notice of Conversion of Loan Type so as to
provide at least the applicable Minimum Notice Period. Any Notice of
Conversion of Loan Type may be modified or revoked by Borrower through the
Banking Day prior to the Minimum Notice Period, and shall thereafter be
irrevocable. Each Notice of Conversion of Loan Type shall be delivered by
first-class mail or telecopy to Agent at the office or to the telecopy number
and during the hours specified in Section 12.1; provided, however, that
Borrower shall promptly deliver to Agent the original of any Notice of
Conversion of Loan Type initially delivered by telecopy. Agent shall promptly
notify each Bank of the contents of each Notice of Conversion of Loan Type.
2.1.7 Prepayments.
(a) Terms of All Prepayments. Upon the
prepayment of any Loan (whether such prepayment is an optional prepayment under
Section 2.1.7(b) or a Mandatory Prepayment), Borrower shall pay to Agent for
the account of the Bank which made such Loan and/or Hedge Bank, as applicable,
(i) all accrued interest to the date of such prepayment on the amount prepaid,
(ii) all accrued fees to the date of such prepayment of the amount being
prepaid, (iii) to the extent required by the terms of the applicable Interest
Rate Agreement, all Hedge Breaking Fees owed by Borrower to such Bank or Hedge
Bank as a result of such prepayment, and (iv) if such prepayment is the
prepayment of a LIBOR Loan on a day other than the last day of an Interest
Period for such LIBOR Loan, all Liquidation Costs incurred by such Bank as a
result of such prepayment. All Mandatory Prepayments of Term Loans shall be
applied to reduce the remaining payments required under Section 2.1.2(d) in
inverse order of maturity. All optional
7
<PAGE> 20
prepayments of the Term Loans shall be applied ratably to the Amortization
Schedule for the Term Loans to reduce the remaining payments required under
Section 2.1.2(d). Borrower may not reborrow the principal amount of any
Construction Loan or Term Loan which is prepaid. Borrower shall terminate or
partially terminate Hedge Transactions such that at no time shall the notional
amount under all of the Hedge Transactions combined exceed the principal amount
of Loans outstanding at such time.
(b) Optional Prepayments. Subject to
Section 2.1.7(a), Borrower may, at its option and without penalty, upon five
Banking Days' notice to Agent, prepay (i) the entire outstanding amount of all
Construction Loans in whole or (ii) any Term Loans in whole or in part in
minimum incremental amounts of $100,000; provided, however, that as a condition
to Borrower's right to make any prepayment of the Construction Loans, Borrower
shall have terminated and repaid all other Commitments hereunder.
(c) Mandatory Prepayments. Borrower
shall prepay (or cause to be prepaid) Loans to the extent required by Section
5.18, 7.1.4, 7.2.5, 7.11, 7.12, or 7.13 of this Agreement, or any other
provision of this Agreement which requires prepayment of Loans (such
prepayment, "Mandatory Prepayment").
2.2 Total Commitments.
2.2.1 Loan Commitment Amounts.
(a) The aggregate principal amount of
all Construction Loans made by the Banks shall not exceed $151,750,000.
Notwithstanding the foregoing, such amount shall be reduced by the amount of
Base Equity and the amount of Subordinated Debt applied to pay Project Costs;
provided, however, such amount shall be reinstated by an amount equal to the
stated amount of any Equity Support Letter of Credit. Such amount shall be
further reduced by the amount elected by Borrower pursuant to Section 2.2.2.
The amount of Construction Loans as determined pursuant to Section 2.2.1(a)
shall be referred to herein as the "Total Construction Loan Commitment").
(b) Notwithstanding anything that may be
construed to the contrary in this Agreement, the aggregate principal amount of
all Term Loans outstanding at any time shall in no event exceed the lesser of
(i) $98,637,500 and (ii) sixty-five percent (65%) of the Final Project Cost,
or, in either case, if such amount is reduced by Borrower to a lower amount
pursuant to Section 2.2.2 (by virtue of a reduction of the Total Construction
Loan Commitment) or by virtue of any optional prepayment or Mandatory
Prepayment, such lower amount (such amount, so reduced from time to time, the
"Total Term Loan Commitment").
2.2.2 Reductions and Cancellations. Borrower may,
from time to time upon five Banking Days written notice to Agent, permanently
reduce, by an amount of $1,000,000 or an integral multiple of $100,000 in
excess thereof or cancel in its entirety the Total Construction Loan
Commitment. Notwithstanding the foregoing, Borrower may not reduce or
8
<PAGE> 21
cancel the Total Construction Loan Commitment if, after giving effect to such
reduction or cancellation, (a) the aggregate principal amount of all
Construction Loans then outstanding would exceed the Total Construction Loan
Commitment, (b) the Available Construction Funds would not, in the reasonable
judgment of Agent and the Independent Engineer, be equal to or exceed remaining
Project Costs, or (c) such reduction or cancellation would cause a violation of
any other provision of this Agreement or the other Credit Documents. Borrower
shall pay to Agent any Commitment Fees then due upon any cancellation and, from
the effective date of any reduction, the Commitment Fees shall be computed on
the basis of the Available Construction Loan Commitment as reduced as a result
of such reduction of the Total Construction Loan Commitment. Once reduced or
cancelled, the Total Construction Loan Commitment may not be increased or
reinstated. Any reductions of the Total Construction Loan Commitment shall
cause a corresponding pro rata reduction in the Total Term Loan Commitment.
Any reductions pursuant to this Section 2.2.2 shall be applied ratably to each
Bank's respective Commitments in accordance with Section 2.5.1.
2.3 Fees.
2.3.1 Advisory Fee; Syndication Fee. Borrower
shall pay to Agent solely for Agent's account the advisory fee and the
syndication fee described in that certain letter from Borrower to Agent dated
the Closing Date.
2.3.2 Annual Agency Fee. Borrower shall pay to
Agent solely for Agent's account an annual agency fee (the "Agency Fee")
payable in advance on the Closing Date and on each anniversary thereof on which
any Loans are outstanding, in an amount equal to the product of (a)(i) for
years beginning prior to Term-Conversion, $175,000 per year, and (ii) for years
beginning after Term-Conversion, $100,000 per year, times (b) the Inflation
Factor.
2.3.3 Loan Commitment Fees. On the last Banking
Day in each calendar quarter (where all or any portion of such calendar quarter
occurs on or after the Closing Date and prior to the Construction Loan Maturity
Date) and on the Construction Loan Maturity Date (or, if the Total Construction
Loan Commitment is cancelled prior to such date, on the date of such
cancellation), Borrower shall pay to Agent, for the benefit of the Banks,
accruing from the Closing Date or the first day of such quarter, as the case
may be, a commitment fee (the "Commitment Fee") for such quarter (or portion
thereof) then ending equal to the product of (a) 0.375% times (b) the daily
average Available Construction Loan Commitment for such quarter (or portion
thereof) times (c) a fraction, the numerator of which is the number of days in
such quarter (or portion thereof) and the denominator of which is the number of
days in that calendar year (365 or 366, as the case may be).
2.4 Other Payment Terms.
2.4.1 Place and Manner. Borrower shall make all
payments due to each Bank or Agent hereunder to Agent, for the account of such
Bank, to Chase Manhattan Bank; Swift: CHASUS33; Fed. Ref.: 021000021; Account
Name: ING (U.S.) Capital Corporation;
9
<PAGE> 22
Account Number: 9301035763, in lawful money of the United States and in
immediately available funds not later than 12:00 noon on the date on which such
payment is due. Any payment made after such time on any day shall be deemed
received on the Banking Day after such payment is received. Agent shall
disburse to each Bank each such payment received by Agent for such Bank, such
disbursement to occur on the day such payment is received if received by 12:00
noon or if otherwise reasonably possible, otherwise on the next Banking Day.
2.4.2 Date. Whenever any payment due hereunder
shall fall due on a day other than a Banking Day, such payment shall be made on
the next succeeding Banking Day, and such extension of time shall be included
in the computation of interest or fees, as the case may be.
2.4.3 Late Payments. If any amounts required to be
paid by Borrower under this Agreement or the other Credit Documents (including
principal or interest payable on any Loan, and any fees or other amounts
otherwise payable to Agent or any Bank) remain unpaid after such amounts are
due, Borrower shall pay interest on the aggregate, unpaid balance of such
amounts from the date due until those amounts are paid in full at a per annum
rate equal to the Default Rate.
2.4.4 Net of Taxes, Etc.
(a) Taxes. Subject to each Bank's
compliance with Section 2.4.7, any and all payments to or for the benefit of
Agent or any Bank by Borrower hereunder or under any other Credit Document
shall be made free and clear of and without deduction, setoff or counterclaim
of any kind whatsoever and in such amounts as may be necessary in order that
all such payments, after deduction for or on account of any present or future
taxes, levies, imposts, deductions, charges or withholdings, and all
liabilities with respect thereto (excluding income and franchise taxes, which
include taxes imposed on or measured by the net income or capital of Agent or
such Bank by any jurisdiction or any political subdivision or taxing authority
thereof or therein solely as a result of a connection between such Bank and
such jurisdiction or political subdivision, other than a connection resulting
solely from executing, delivering or performing its obligations or receiving a
payment under, or enforcing, this Agreement or any Note) (all such non-excluded
taxes, levies, imposts, deductions, charges, withholdings and liabilities being
hereinafter referred to as "Taxes"), shall be equal to the amounts otherwise
specified to be paid under this Agreement and the other Credit Documents. If
Borrower shall be required by law to withhold or deduct any Taxes from or in
respect of any sum payable hereunder or under any other Credit Document to
Agent or any Bank, (i) the sum payable shall be increased as may be necessary
so that after making all required deductions (including deductions applicable
to additional sums payable under this Section 2.4.4, Agent or such Bank
receives an amount equal to the sum it would have received had no such
deductions been made, (ii) Borrower shall make such deductions and (iii)
Borrower shall pay the full amount deducted to the relevant taxation authority
or other authority in accordance with applicable law. If Borrower shall make
any payment under this Section 2.4.4 to or for the benefit of Agent or any Bank
with respect to Taxes and if Agent or such Bank shall claim any credit or
deduction for such Taxes against any other taxes payable by Agent or such Bank
to any taxing jurisdiction then Agent
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<PAGE> 23
or such Bank shall pay to Borrower an amount equal to the amount by which such
other taxes are actually reduced; provided that the aggregate amount payable by
Agent or such Bank pursuant to this sentence shall not exceed the aggregate
amount previously paid by Borrower with respect to such Taxes. In addition,
Borrower agrees to pay any present or future stamp, recording or documentary
taxes and any other excise or property taxes, charges or similar levies (not
including income or franchise taxes) that arise under the laws of the United
States of America, the State of New York or the State of Texas from any payment
made hereunder or under any other Credit Document or from the execution or
delivery or otherwise with respect to this Agreement or any other Credit
Document (hereinafter referred to as "Other Taxes").
(b) Indemnity. Borrower shall indemnify
each Bank for the full amount of Taxes and Other Taxes (including any Taxes or
Other Taxes imposed by any jurisdiction on amounts payable under this Section
2.4.4 paid by any Bank, or any liability (including penalties, interest and
expenses) arising therefrom or with respect thereto, whether or not such Taxes
or Other Taxes were correctly or legally asserted; provided that Borrower shall
not be obligated to indemnify any Bank for any penalties, interest or expenses
relating to Taxes or Other Taxes arising from the indemnitee's gross negligence
or willful misconduct. Each Bank agrees to give written notice to Borrower of
the assertion of any claim against such Bank relating to such Taxes or Other
Taxes as promptly as is practicable after being notified of such assertion, and
in no event later than one hundred eighty (180) days after the principal
officer of such Bank responsible for administering this Agreement obtains
knowledge thereof; provided that any Bank's failure to notify Borrower of such
assertion within such one hundred eighty (180) days period shall not relieve
Borrower of its obligation under this Section 2.4.4 with respect to Taxes or
Other Taxes arising prior to the end of such period, but shall relieve Borrower
of its obligations under this Section 2.4.4 with respect to Taxes or Other
Taxes between the end of such period and such time as Borrower receives notice
from such Bank as provided herein. Payments by Borrower pursuant to this
indemnification shall be made within 30 days from the date such Bank makes
written demand therefor (submitted through Agent), which demand shall be
accompanied by a certificate describing in reasonable detail the basis thereof.
Each Bank agrees to repay to Borrower any refund (including that portion of any
interest that was included as part of such refund with respect to Taxes or
Other Taxes paid by Borrower pursuant to this Section 2.4.4) received by such
Bank for Taxes or Other Taxes that were paid by Borrower pursuant to this
Section 2.4.4 and to contest, with the approval and participation of and at the
expense of Borrower, any such Taxes or Other Taxes which such Bank or Borrower
reasonably believes not to have been properly assessed.
(c) Notice. Within 30 days after the
date of any payment of Taxes by Borrower, Borrower shall furnish to Agent, at
its address referred to in Section 12.1, the original or a certified copy of a
receipt evidencing payment thereof. Borrower shall compensate each Bank for
all reasonable losses and expenses sustained by such Bank as a result of any
failure by Borrower to so furnish such copy of such receipt.
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<PAGE> 24
(d) Survival of Obligations. The
obligations of Borrower under this Section 2.4.4 shall survive the termination
of this Agreement and the repayment of the Obligations.
2.4.5 Application of Payments. Payments made under
this Agreement or the other Credit Documents and other amounts received by
Agent and the Banks under this Agreement or the other Credit Documents shall
first be applied to any fees, costs, charges or expenses payable to Agent or
the other Banks hereunder or under the other Credit Documents, next to any
accrued but unpaid interest then due and owing, and then to outstanding
principal then due and owing or otherwise to be prepaid.
2.4.6 Failure to Pay Agent. Unless Agent shall
have received notice from Borrower at least two Banking Days prior to the date
on which any payment is due to the Banks hereunder that Borrower will not make
such payment in full, Agent may assume that Borrower has made such payment in
full to Agent on such date and Agent may, in reliance upon such assumption,
cause to be distributed to each Bank on such due date an amount equal to the
amount then due such Bank. If and to the extent Borrower shall not have so
made such payment in full to Agent, such Bank shall repay to Agent forthwith
upon demand such amount distributed to such Bank, together with interest
thereon, for each day from the date such amount is distributed to such Bank
until the date such Bank repays such amount to Agent, at the Federal Funds Rate
for the first five days after such date, and subsequent thereto at the Base
Rate. A certificate of Agent submitted to any Bank with respect to any amounts
owing by such Bank under this Section 2.4.6 shall be conclusive in the absence
of manifest error.
2.4.7 Withholding Exemption Certificates. Agent on
the Closing Date and each Bank upon becoming a Bank hereunder including any
entity to which any Bank grants a participation, or otherwise transfers its
interest in this Agreement, agree that they will deliver to Borrower and Agent
(and Agent agrees that it will deliver to Borrower) either (a) a statement that
it is incorporated under the laws of the United States of America or a state
thereof or (b) if it is not so incorporated, a letter in the form of Exhibit
J-1 or Exhibit J-2, as appropriate, and two duly completed copies of United
States Internal Revenue Service Form 1001 or 4224 or successor applicable form,
as the case may be, certifying in each case that such Bank is entitled to
receive payments under this Agreement without deduction or withholding of any
United States federal income taxes. Each Bank which delivers to Borrower and
Agent a Form 1001 or 4224 pursuant to the preceding sentence further undertakes
to deliver to Borrower and Agent further copies of the said letter and Form
1001 or 4224, or successor applicable forms, or other manner of certification
or procedure, as the case may be, on or before the date that any such letter or
form expires or becomes obsolete or within a reasonable time after gaining
knowledge of the occurrence of any event requiring a change in the most recent
letter and forms previously delivered by it to Borrower, and such extensions or
renewals thereof as may reasonably be requested by Borrower, certifying in the
case of a Form 1001 or 4224 that such Bank is entitled to receive payments
under this Agreement without deduction or withholding of any United States
federal income taxes, unless in any such cases an event (including any change
in treaty, law or regulation) has occurred prior to the date on which any such
delivery would otherwise be required which renders all such forms
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inapplicable or which would prevent a Bank from duly completing and delivering
any such letter or form with respect to it and such Bank advises Borrower that
it is not capable of receiving payments without any deduction or withholding of
United States federal income tax, and in the case of Form W-8 or W-9,
establishing an exemption from United States backup withholding tax. The
Borrower shall not be obligated, however, to pay any additional amounts in
respect of United States Federal income tax pursuant to Section 2.4.4 (or make
an indemnification payment pursuant to Section 2.4.4) to any Bank (including
any entity to which any Bank sells, assigns, grants a participation in, or
otherwise transfers its rights under this Agreement) if the obligation to pay
such additional amounts (or such indemnification) would not have arisen but for
a failure of such Bank to comply with its obligations under this Section 2.4.7.
2.5 Pro Rata Treatment.
2.5.1 Borrowings, Commitment Reductions, Etc.
Except as otherwise provided herein, (a) each Borrowing consisting of
Construction Loans and Term Loans and each reduction of the Total Construction
Loan Commitment shall be made or allocated among the Banks pro rata according
to their respective Proportionate Shares of such Loans, (b) each payment of
principal of and interest on Construction Loans and Term Loans shall be made or
shared among the Banks holding such Loans pro rata according to the respective
unpaid principal amounts of such Loans held by such Banks and (c) each payment
of Commitment Fees shall be shared among the Banks pro rata according to (i)
their respective Proportionate Shares of the Loans to which such fees apply and
(ii) in the case of each Bank which becomes a Bank hereunder after the date
hereof, the date upon which such Bank so became a Bank.
2.5.2 Sharing of Payments, Etc. If any Bank shall
obtain any payment (whether voluntary, involuntary, through the exercise of any
right of setoff, or otherwise) on account of Loans owed to it, in excess of its
ratable share of payments on account of such Loans obtained by all Banks
entitled to such payments, such Bank shall forthwith purchase from the other
Banks such participation in the Loans, as the case may be, as shall be
necessary to cause such purchasing Bank to share the excess payment ratably
with each of them; provided, however, that if all or any portion of such excess
payment is thereafter recovered from such purchasing Bank, such purchase from
such Bank shall be rescinded and each other Bank shall repay to the purchasing
Bank the purchase price to the extent of such recovery together with an amount
equal to such other Bank's ratable share (according to the proportion of (a)
the amount of such other Bank's required repayment to (b) the total amount so
recovered from the purchasing Bank) of any interest or other amount paid or
payable by the purchasing Bank in respect of the total amount so recovered.
Borrower agrees that any Bank so purchasing a participation from another Bank
pursuant to this Section 2.5.2 may, to the fullest extent permitted by law,
exercise all its rights of payment (including the right of setoff) with respect
to such participation as fully as if such Bank were the direct creditor of
Borrower in the amount of such participation.
2.6 Change of Circumstances.
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2.6.1 Inability to Determine Rates. If, on or
before the first day of any Interest Period for any LIBOR Loans, (a) Agent
determines that the LIBO Rate for such Interest Period cannot be adequately and
reasonably determined due to the unavailability of funds in or other
circumstances affecting the London interbank market, or (b) Banks holding
aggregate Proportionate Shares of 33-1/3% or more shall advise Agent that (i)
the rates of interest for such LIBOR Loans do not adequately and fairly reflect
the cost to such Banks of making or maintaining such Loans or (ii) deposits in
Dollars in the London interbank market are not available to such Banks (as
conclusively certified by each such Bank in good faith in writing to Agent and
to Borrower) in the ordinary course of business in sufficient amounts to make
and/or maintain their LIBOR Loans, Agent shall immediately give notice of such
condition to Borrower. After the giving of any such notice and until Agent
shall otherwise notify Borrower that the circumstances giving rise to such
condition no longer exist, Borrower's right to request the making of or
conversion to, and the Banks' obligations to make or convert to LIBOR Loans
shall be suspended. Any LIBOR Loans outstanding at the commencement of any
such suspension shall be converted at the end of the then current Interest
Period for such Loans into Base Rate Loans unless such suspension has then
ended.
2.6.2 Illegality. If, after the date of this
Agreement, the adoption of any Governmental Rule, any change in any
Governmental Rule or the application or requirements thereof (whether such
change occurs in accordance with the terms of such Governmental Rule as
enacted, as a result of amendment, or otherwise), any change in the
interpretation or administration of any Governmental Rule by any Governmental
Authority, or compliance by any Bank or Borrower with any request or directive
(whether or not having the force of law) of any Governmental Authority (a
"Change of Law") shall make it unlawful or impossible for any Bank to make or
maintain any LIBOR Loan, such Bank shall immediately notify Agent and Borrower
of such Change of Law. Upon receipt of such notice, (a) Borrower's right to
request the making of or conversion to, and the Bank's obligations to make or
convert to, LIBOR Loans shall be suspended for so long as such condition shall
exist, and (b) Borrower shall, at the request of such Bank, either (i) pursuant
to Section 2.1.6, convert any then outstanding LIBOR Loans into Base Rate Loans
at the end of the current Interest Periods for such Loans, or (ii) immediately
repay pursuant to Section 2.1.7 or convert LIBOR Loans of the affected Type
into Base Rate Loans if such Bank shall notify Borrower that such Bank may not
lawfully continue to fund and maintain such Loans. Any conversion or
prepayment of LIBOR Loans made pursuant to the preceding sentence prior to the
last day of an Interest Period for such Loans shall be deemed a prepayment
thereof for purposes of Section 2.7.
2.6.3 Increased Costs. If, after the date of this
Agreement, any Change of Law:
(a) Shall subject any Bank to any tax,
duty or other charge with respect to any LIBOR Loan or Commitment, or shall
change the basis of taxation of payments by Borrower to any Bank on such a Loan
or with respect to any Commitment (except for Taxes, Other Taxes or changes in
the rate of taxation on the overall net income of any Bank); or
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(b) Shall impose, modify or hold
applicable any reserve, special deposit or similar requirement (without
duplication of any reserve requirement included within the applicable Interest
Rate through the definition of "Reserve Requirement") against assets held by,
deposits or other liabilities in or for the account of, advances or loans by,
or any other acquisition of funds by any Bank for any LIBOR Loan; or
(c) Shall impose on any Bank any other
condition directly related to any LIBOR Loan or Commitment;
and the effect of any of the foregoing is to increase the cost to such Bank of
making, issuing, creating, renewing, participating in (subject to the
limitations in Section 10.13) or maintaining any such LIBOR Loan or Commitment
or to reduce any amount receivable by such Bank hereunder; then Borrower shall
from time to time, upon demand by such Bank, pay to such Bank additional
amounts sufficient to reimburse such Bank for such increased costs or to
compensate such Bank for such reduced amounts. A certificate setting forth in
reasonable detail the amount of such increased costs or reduced amounts and the
basis for determination of such amount, submitted by such Bank to Borrower,
shall, in the absence of manifest error, be conclusive and binding on Borrower
for purposes of this Agreement.
2.6.4 Capital Requirements. If any Bank determines
that (a) any Change of Law after the date of this Agreement increases the
amount of capital required or expected to be maintained by such Bank (or the
Lending Office of such Bank) or any Person controlling such Bank (a "Capital
Adequacy Requirement") and (b) the amount of capital maintained by such Bank or
such Person which is attributable to or based upon the Loans, the Commitments
or this Agreement must be increased as a result of such Capital Adequacy
Requirement (taking into account such Bank's or such Person's policies with
respect to capital adequacy), Borrower shall pay to Agent on behalf of such
Bank or such Person, upon demand of Agent on behalf of such Bank or such
Person, such amounts as such Bank or such Person shall reasonably determine are
necessary to compensate such Bank or such Person for the increased costs to
such Bank or such Person of such increased capital. A certificate of such Bank
or such Person, setting forth in reasonable detail the computation of any such
increased costs, delivered to Borrower by Agent on behalf of such Bank or such
Person shall, in the absence of manifest error, be conclusive and binding on
Borrower for purposes of this Agreement.
2.6.5 Notice; Participating Banks' Rights. Each
Bank will notify Borrower of any event occurring after the date of this
Agreement that will entitle such Bank to compensation pursuant to this Section
2.6, as promptly as practicable, and in no event later than 90 days after the
principal officer of such Bank responsible for administering this Agreement
obtains knowledge thereof; provided that any Bank's failure to notify Borrower
within such 90 day period shall not relieve Borrower of its obligation under
this Section 2.6.5 with respect to claims arising prior to the end of such
period, but shall relieve Borrower of its obligations under this Section 2.6.5
with respect to the time between the end of such period and such time as
Borrower receives notice from the indemnitee as provided herein. No Person
purchasing from a Bank a participation in any Commitment (as opposed to an
assignment) shall be entitled to any payment from or on behalf of
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Borrower pursuant to Section 2.6.3 or Section 2.6.4 which would be in excess of
the applicable proportionate amount (based on the portion of the Commitment in
which such Person is participating) which would then be payable to such Bank if
such Bank had not sold a participation in that portion of the Commitment.
2.7 Funding Losses. If Borrower shall (a) repay or
prepay any LIBOR Loans on any day other than the last day of an Interest Period
for such Loans (whether an optional prepayment or a Mandatory Prepayment), (b)
fail to borrow any LIBOR Loans in accordance with a Notice of Borrowing
delivered to Agent (whether as a result of the failure to satisfy any
applicable conditions or otherwise), (c) fail to convert any Loans into LIBOR
Loans in accordance with a Notice of Conversion of Loan Type delivered to Agent
(whether as a result of the failure to satisfy any applicable conditions or
otherwise), or (d) fail to make any prepayment in accordance with any notice of
prepayment delivered to Agent; Borrower shall, upon demand by any Bank,
reimburse such Bank for all costs and losses incurred by such Bank as a result
of such repayment, prepayment or failure ("Liquidation Costs"). Borrower
understands that such costs and losses may include losses incurred by a Bank as
a result of funding and other contracts entered into by such Bank to fund LIBOR
Loans. Each Bank demanding payment under this Section 2.7 shall deliver to
Borrower a certificate setting forth in reasonable detail the basis for and the
amount of costs and losses for which demand is made. Such a certificate so
delivered to Borrower shall, in the absence of manifest error, be conclusive
and binding as to the amount of such loss for purposes of this Agreement.
2.8 Alternate Office; Minimization of Costs.
2.8.1 To the extent reasonably possible, each Bank
shall designate an alternative Lending Office with respect to its LIBOR Loans
and otherwise take any reasonable actions to reduce any liability of Borrower
to any Bank under Section 2.4.4, 2.6.3 or 2.6.4, or to avoid the unavailability
of any Type of Loans under Section 2.6.2 so long as such Bank, in its sole
discretion, does not determine that such designation is disadvantageous to such
Bank.
2.8.2 If and with respect to each occasion that a
Bank either makes a demand for compensation pursuant to Section 2.4.4, 2.4.7,
2.6.3 or 2.6.4 or is unable for a period of three consecutive months to fund
LIBOR Loans pursuant to Section 2.6.2 or such Bank wrongfully fails to fund a
Loan, Borrower may, upon at least five Banking Days' prior irrevocable written
notice to each of such Bank and Agent, in whole permanently replace the
Commitment of such Bank; provided that Borrower shall replace such Commitment
with the Commitment of a commercial bank reasonably satisfactory to the Agent.
Such replacement Bank shall upon the effective date of replacement purchase the
Obligations owed to such replaced Bank for the aggregate amount thereof and
shall thereupon for all purposes become a "Bank" hereunder. Such notice from
Borrower shall specify an effective date for the replacement of such Bank's
Commitment, which date shall not be later than the tenth day after the day such
notice is given. On the effective date of any replacement of such Bank's
Commitment pursuant to this Section 2.8.2, Borrower shall pay to Agent for the
account of such Bank (a) any fees due to such Bank to the date of such
replacement; (b) accrued interest on the principal amount of outstanding Loans
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held by such Bank to the date of such replacement, and (c) the amount or
amounts requested by such Bank pursuant to each of Sections 2.4.4, 2.4.7, 2.6.3
and 2.6.4, as applicable. Borrower will remain liable to such replaced Bank
for any Liquidation Costs that such Bank may sustain or incur as a consequence
of repayment of such Bank's Loans (unless such Bank has defaulted on its
obligation to fund a Loan hereunder). Upon the effective date of repayment of
any Bank's Loans and termination of such Bank's Commitment pursuant to this
Section 2.8.2, such Bank shall cease to be a Bank hereunder. No such
termination of any such Bank's Commitment and the purchase of such Bank's Loans
pursuant to this Section 2.8.2 shall affect (i) any liability or obligation of
Borrower or any other Bank to such terminated Bank which accrued on or prior to
the date of such termination or (ii) such terminated Bank's rights hereunder in
respect of any such liability or obligation.
2.8.3 Any Bank may designate a Lending Office other
than that set forth on Exhibit H and may assign all of its interests under the
Credit Documents, and its Notes, to such Lending Office; provided that such
designation and assignment do not at the time of such designation and
assignment increase the reasonably foreseeable liability of Borrower under
Sections 2.4.4, 2.6.3, or 2.6.4 or make an Interest Rate option unavailable
pursuant to Section 2.6.2.
ARTICLE 3 - CONDITIONS PRECEDENT
3.1 Conditions Precedent to the Closing Date. The
obligation of the Banks to make the initial Construction Loans is subject to
the prior satisfaction of each of the following conditions (unless waived in
writing by Agent with the consent of the Banks):
3.1.1 Resolutions. Delivery to Agent of a copy of
one or more resolutions or other authorizations of Borrower and each of the
Partners, Shareholders, Construction Manager, Project Manager, Operator and
each Equity Party, certified by the appropriate officers of each such entity as
being in full force and effect on the Closing Date, authorizing, as applicable,
the Borrowings herein provided for and the execution, delivery and performance
of this Agreement and the other Operative Documents and any instruments or
agreements required hereunder or thereunder to which such entity is a party.
3.1.2 Incumbency. Delivery to Agent of a
certificate satisfactory in form and substance to Agent, from the Managing
Partner of Borrower and from each of the Partners, Shareholders, Construction
Manager, Project Manager, Operator and each Equity Party, signed by the
appropriate authorized officer of each such entity and dated the Closing Date,
as to the incumbency of the natural persons authorized to execute and deliver
this Agreement and the other Operative Documents and any instruments or
agreements required hereunder or thereunder to which such entity is a party.
3.1.3 Formation Documents. Delivery to Agent of
(a) a copy of the Partnership Agreement, certified by the secretary or an
assistant secretary of the Managing Partner as being true, current and complete
on the Closing Date, and any related agreements or certificates
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filed in accordance with applicable state law, and (b) copies of the articles
of incorporation or certificate of incorporation or charter of each Major
Project Participant other than Borrower (or any Equity LC Issuer), certified,
if requested by the Agent, by the secretary of state of the state of
incorporation, and (c) copies of the Bylaws of each of the Partners and
Shareholders, Construction Manager, Project Manager, Operator and each Equity
Party, certified by its secretary or an assistant secretary.
3.1.4 Good Standing Certificates. Delivery to
Agent of certificates issued by the Secretary of State of Texas and, if other
than such state, the state of formation of each Major Project Participant other
than any Equity LC Issuer certifying that such Major Project Participant is in
good standing and is qualified to do business in, and has paid all franchise
taxes or similar taxes due to, Texas (if applicable) and its state of
formation.
3.1.5 Satisfactory Proceedings. All corporate,
partnership and legal proceedings and all instruments in connection with the
transactions contemplated by this Agreement shall be satisfactory in form and
substance to Agent, and Agent shall have received all information and copies of
all documents, including records of corporate or partnership proceedings and
copies of any approval by any Governmental Authority required in connection
with any transaction herein contemplated, which Agent may reasonably have
requested in connection herewith, such documents where appropriate to be
certified by proper corporate or partnership officers or Governmental
Authorities.
3.1.6 Operative Documents. Delivery to Agent of
executed originals of each Credit Document (other than any Equity Support
Letter of Credit, Debt Service Reserve Letter of Credit, Fuel Supply Reserve
Letter of Credit or Emissions Offsets Reserve Letter of Credit) and a certified
list of and true and correct copies of, each Project Document then in effect,
any supplements or amendments thereto, all of which shall be in form and
substance satisfactory to Agent, shall have been duly authorized, executed and
delivered by the parties thereto, and all of which Project Documents shall be
certified by a Responsible Officer of Borrower as being true, complete and
correct and in full force and effect on the Closing Date pursuant to the
certificate delivered as provided in the following paragraph, which certificate
shall state that neither Borrower nor, to Borrower's knowledge, any other party
to any Project Document is or, but for the passage of time or giving of notice
or both will be, in breach of any material obligation thereunder, and that all
conditions precedent to the performance of the parties under the Project
Documents then required to have been performed have been satisfied.
3.1.7 Certificate of Borrower. Agent shall have
received a certificate, dated as of the Closing Date, signed by a Responsible
Officer of Borrower, in substantially the form of Exhibit F-1.
3.1.8 Legal Opinions. Delivery to Agent of legal
opinions of counsel to each Major Project Participant (other than any Equity LC
Issuer), in form and substance satisfactory to the Agent.
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3.1.9 Certificate of Insurance Consultant.
Delivery to Agent of the Insurance Consultant's certificate, in substantially
the form of Exhibit F-2, with the Insurance Consultant's report, in form and
substance satisfactory to Agent, attached thereto.
3.1.10 Insurance. Insurance complying with Exhibit
K shall be in full force and effect and Agent shall have received (a) a
certificate from Borrower's insurance broker(s), dated as of the Closing Date
and identifying underwriters, type of insurance, insurance limits and policy
terms, listing the special provisions required as set forth in Exhibit K,
describing the insurance obtained and stating that such insurance is in full
force and effect and that all premiums due thereon through the Construction
Loan Maturity Date have been paid and that, in the opinion of such broker(s),
such insurance complies with Exhibit K, and (b) certified copies of all
policies evidencing such insurance (or a binder, commitment or certificates
signed by the insurer or a broker authorized to bind the insurer), in form and
substance satisfactory to Agent.
3.1.11 Certificate of the Independent Engineer.
Delivery to Agent of the Independent Engineer's certificate, in substantially
the form of Exhibit F-3, with the Independent Engineer's report, in form and
substance satisfactory to Agent, attached thereto.
3.1.12 Reports of the Borrower's Environmental
Consultant. Delivery to Agent of the Borrower's Environmental Consultant's
reports along with the corresponding reliance letters, each in form and
substance satisfactory to Agent.
3.1.13 Certificate of the Fuel Consultant. Delivery
to Agent of the Fuel Consultant's certificate, in substantially the form of
Exhibit F-4, with the Fuel Consultant's report, in form and substance
satisfactory to Agent, attached thereto.
3.1.14 Certificate of Power Marketing Consultant.
Delivery to Agent of the Power Marketing Consultant's certificate, in
substantially the form of Exhibit F-5, with the Power Marketing Consultant's
report, in form and substance satisfactory to Agent, attached thereto.
3.1.15 Power Marketing Plan. Delivery to Agent of a
plan with respect to power marketing setting forth Borrower's good faith
assessment of Borrower's projected sales of power within ERCOT, which plan
shall not in any way be construed to modify or limit Borrower's rights and
obligations set forth herein, substantially in the form of Exhibit G-2 (the
"Power Marketing Plan").
3.1.16 Schedule of Applicable Permits and Applicable
Third Party Permits. Delivery to Agent of Exhibit G-3, the schedule of Permits
required to construct and operate the Project or required to be obtained by any
Person (other than Borrower) that is party to any Project Document in order to
perform its obligations thereunder, satisfactory in form and substance to
Agent, together with copies of each Applicable Permit and Applicable Third
Party Permit listed on Parts I(A) and I(B) of Exhibit G-3, each satisfactory in
form and substance to Agent. Except as disclosed in Exhibit G-3, Borrower
shall have duly obtained or been assigned and there shall
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be in full force and effect in Borrower's name, and not subject to any current
legal proceeding or to any unsatisfied condition that could reasonably be
expected to allow material modification or revocation of, and all applicable
appeal periods shall have expired with respect to, the Applicable Permits for
the Project set forth on Parts I(A) and I(B) of Exhibit G-3, constituting in
Agent's reasonable opinion all of the Applicable Permits as of the Closing
Date. Except as disclosed on Exhibit G-3, each Major Project Participant with
respect to which responsibility for an Applicable Third Party Permit is
indicated in Part I(B) of Exhibit G-3 shall have duly obtained or been assigned
such Applicable Third Party Permit and there shall be in full force and effect
in such Person's name, and not subject to any current legal proceeding or to
any unsatisfied condition that could reasonably be expected to allow material
modification or revocation of, and all applicable appeal periods shall have
expired with respect to, each Applicable Third Party Permit set forth on Part
I(B) of Exhibit G-3, constituting in Agent's reasonable opinion all of the
Applicable Third Party Permits as of the Closing Date. Part II(A) of Exhibit
G-3 shall list all other Permits required by Borrower to construct and operate
the Project as contemplated by the Operative Documents. Part II(B) of Exhibit
G-3 shall list all other material Permits required by any other Major Project
Participant to perform its obligations under the Operative Documents to which
it is a party. The Permits listed in Parts II(A) and II(B) of Exhibit G-3
shall, in Agent's reasonable opinion, be timely obtainable without material
difficulty, expense or delay by Borrower or the applicable other Major Project
Participant, respectively. Except as disclosed in Exhibit G-3 the Permits
listed in Part I(A) and I(B) of Exhibit G-3 shall not be subject to any
restriction, condition, limitation or other provision that could reasonably be
expected to have a Material Adverse Effect.
3.1.17 No Change in Tax Laws. No change shall have
occurred, since the date upon which this Agreement was executed and delivered,
in any law or regulation or interpretation thereof that would subject any Bank
to any material unreimbursed Tax or Other Tax.
3.1.18 Absence of Litigation. (a) No action, suit,
proceeding or investigation shall have been instituted or threatened against
Borrower and (b) no order, judgment or decree shall have been issued or
proposed to be issued by any Governmental Authority that, as a result of the
construction, ownership, leasing or operation of the Project, the sale of
electricity or steam therefrom or the entering into of any Operative Document
or any transaction contemplated hereby or thereby, would cause or deem the
Banks, Borrower or any Affiliate of any of them to be subject to, or not
exempted from, regulation under the FPA or PUHCA or under state laws and
regulations respecting the rates or the financial or organizational regulation
of electric utilities.
3.1.19 Payment of Filing Fees. All amounts required
to be paid to or deposited with Agent, and all taxes, fees and other costs
payable in connection with the execution, delivery, recordation and filing of
the documents and instruments referred to in this Section 3.1, shall have been
paid in full or, as approved by Agent, provided for.
3.1.20 Financial Statements. Agent shall have
received the most recent annual financial statements (audited if available) or
Form 10-K and most recent quarterly financial
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statements or Form 10-Q from Borrower and each other Major Project Participant
(other than the Partners) (or, in the case of the Fuel Supplier and HL&P, their
respective parent corporations) other than any Equity LC Issuer, together (in
the case of Borrower and its Affiliates who are Major Project Participants)
with certificates from the appropriate Responsible Officer thereof, stating
that no material adverse change in the consolidated assets, liabilities,
operations or financial condition of such Person has occurred from those set
forth in the most recent financial statements or the balance sheet, as the case
may be, provided to Agent.
3.1.21 UCC Reports. Agent shall have received a UCC
report of a date reasonably close to the Closing Date for each of the
jurisdictions in which the UCC-1 financing statements, are intended to be filed
in respect of the Collateral, showing that upon due filing (assuming such
filing or recordation occurred on the date of such respective reports), the
security interests created under such Collateral Documents will be prior to all
other financing statements, or other security documents wherein the security
interest is perfected by filing in respect of the Collateral.
3.1.22 Project Budget. Borrower shall have
furnished Agent a budget in substantially the form of Exhibit G-4 (the "Project
Budget") for all anticipated costs to be incurred in connection with the
construction and start-up of the Project, including in such budget all
construction and non-construction costs, and including all interest, taxes and
other carrying costs, and such other information as Agent may require, together
with a balanced statement of sources and uses of proceeds (and any other funds
necessary to complete the Project), broken down as to separate construction
phases and components, which Project Budget shall be satisfactory to Agent.
3.1.23 Base Case Project Projections. Borrower
shall have furnished to Agent the Base Case Project Projections of operating
expenses and cash flow for the Project showing a minimum projected annual Debt
Service Coverage Ratio of 2.11 and an average projected annual Debt Service
Coverage Ratio of 2.41 over the term of the Term Loans and otherwise in
substantially the form of Exhibit G-5 and in form and substance satisfactory to
Agent.
3.1.24 No Material Adverse Change. Since April 22,
1996, in the reasonable judgment of Agent, there shall not have occurred any
material adverse change in the Project Budget, Project Schedule or Base Case
Project Projections, in the economics or feasibility of constructing and/or
operating the Project, or in the financial condition, business, prospects or
property of any Major Project Participant, which could reasonably be expected
to have a Material Adverse Effect.
3.1.25 A.L.T.A. Surveys. Agent shall have received
A.L.T.A. surveys of the Site and the Easements, satisfactory in form and
substance to Agent and the Title Insurer, reasonably current and certified to
Agent by Weisser Engineering Co. or another licensed surveyor satisfactory to
Agent, showing (a) as to the Site, the exact location and dimensions thereof,
including the location of all means of access thereto and all easements
relating thereto and showing the perimeter within which all foundations are or
are to be located; (b) as to the Easements, the exact location and dimensions
thereof, including the location of all means of access thereto, and
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all improvements or other encroachments in or on the Easements; (c) the
existing utility facilities servicing the Project (including water,
electricity, gas, telephone, sanitary sewer and storm water distribution and
detention facilities); (d) that such existing improvements do not encroach or
interfere with adjacent property or existing easements or other rights (whether
on, above or below ground), and that there are no gaps, gores, projections,
protrusions or other survey defects; (e) whether the Site or any portion
thereof is located in a special earthquake or flood hazard zone; and (f) that
there are no other matters that could reasonably be expected to be disclosed by
a survey constituting a defect in title other than Permitted Encumbrances.
3.1.26 Title Policy. Borrower shall have delivered
to Agent a lender's A.L.T.A. policy of title insurance, together with such
endorsements as are required by Agent, or a commitment to issue such a policy
(such policy and endorsements or commitment being hereinafter referred to as
the "Title Policy"), in the amount of $151,750,000 with such reinsurance as is
satisfactory to Agent, issued by the Title Insurer in form and substance
satisfactory to Agent, insuring (or agreeing to insure) that:
(a) Borrower has a good, marketable and
insurable title to or right to control, occupy and use the Site and the
Easements, free and clear of liens, encumbrances or other exceptions to title
except those exceptions specified on Exhibit D-10 ("Permitted Encumbrances");
and
(b) the Deed of Trust is (or will be
when recorded) a valid first lien on the Mortgaged Property, free and clear of
all liens, encumbrances and exceptions to title whatsoever, other than
Permitted Encumbrances.
3.1.27 Qualifying Facility Status. The Project
shall have complied with the requirements of 18 C.F.R. Section 209.207
required to be complied with as of the Closing Date and delivered to Agent a
certificate of FERC certifying the Project as a Qualifying Facility.
3.1.28 Notice to Proceed. Each Contractor shall
have been given an unconditional notice to proceed or otherwise been
unconditionally directed to begin performance under the Construction Contract
to which it is a party, and shall have acknowledged receipt thereof, on or
prior to the Closing Date.
3.1.29 Establishment of Accounts. The Accounts
required under Article 7 shall have been established to the satisfaction of the
Agent.
3.1.30 Representations and Warranties of Partners
and Borrower. Each representation and warranty of the Partners under the
Credit Documents and each representation and warranty of Borrower under the
Credit Documents shall be true and correct.
3.1.31 Utilities. Agent has received evidence
acceptable to Agent in its sole discretion that all necessary utility services
are either contracted for, or readily available on reasonable economic terms,
at the Project.
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3.1.32 Interest Rate Hedges. Borrower shall have
entered into the Interest Rate Agreement and that certain letter agreement
described in Section 5.22.
3.1.33 Key Personnel. Construction Manager shall
have retained and is engaging, for the performance of its obligations under the
Construction Management Agreement, key management personnel which includes the
key personnel that were engaged in connection with the development of the Sumas
project or which are otherwise acceptable to Agent and Independent Engineer.
Such personnel shall include without limitation, Angelo Urbani, as the home
office construction manager, and Bill Small, as the project site manager or
such other personnel as are reasonably acceptable to Agent.
3.1.34 Project Schedule. Borrower shall have
furnished the Project Schedule in substantially the form of Exhibit G-6.
3.1.35 Reports of Borrower's Tax Consultants.
Delivery to Agent of sales tax and real property tax reports along with
corresponding reliance letters from Arthur Andersen, LLP, each in form and
substance satisfactory to Agent.
3.1.36 Reports of Borrower's HCC Evaluation
Consultant. Delivery to Agent of an HCC evaluation and assessment report along
with a corresponding reliance letter from Pace Consultants, each in form and
substance satisfactory to Agent.
3.1.37 Phillips Documents. Phillips shall have
provided to Agent (a) a letter confirming the environmental condition of the
properties subject to the Easements granted to Borrower pursuant to the Lease
and (b) a letter confirming that Phillips has not entered into any agreement
nor has otherwise subjected HCC to any noise ordinance or regulation or other
noise restrictions, each in form and substance satisfactory to Agent.
3.1.38 Mechanics' Lien Indemnity. Calpine shall
have executed and delivered an indemnity in favor of the Banks with respect to
mechanics' liens which could gain priority over the Deed of Trust.
3.1.39 Port Authority License. The Port Authority
shall have delivered a letter to Agent, stating (i) the Port Authority has
authorized the execution and delivery of a license in favor of Borrower
relating to certain transmission lines for the Project, (ii) the Authority will
execute and deliver such license promptly after preparation thereof, and (iii)
the Port Authority will, concurrently with such execution, execute and deliver
consent to assignment of such license to Agent, in the form attached to such
letter as an exhibit.
3.1.40 Phillips License. Phillips shall have
delivered a letter to Agent stating that Phillips has applied or will promptly
apply for an amendment to the Oil, Gas, etc. Pipeline License (Railroad
Right-of-Way) dated April 1, 1990 between the Port and Phillips 66 Company, as
predecessor in interest to Phillips so as to permit Borrower to construct
within the
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area described in Exhibit A to the license the improvements contemplated in the
Development and Construction Agreement.
3.2 Conditions Precedent to Each Construction Credit
Event. The obligation of the Banks to make each Construction Loan (including
the first Construction Loan and the final Construction Loan) and to disburse
non-Loan proceeds from the Construction Account (each of the foregoing, a
"Construction Credit Event"), is subject to the prior satisfaction of each of
the following conditions:
3.2.1 Credit Event Conditions Satisfied. The
conditions set forth in Section 3.4 shall have been satisfied and Agent shall
have received a certificate from Borrower dated the date such Construction
Credit Event is proposed to occur, certifying to the matters set forth in
Section 3.4.
3.2.2 Monthly Drawdown Frequency. Construction
Loans shall be made no more frequently than one time per month.
3.2.3 Notice of Borrowing. Borrower shall have
delivered a Notice of Borrowing to Agent in accordance with the procedures
specified in Section 2.1.
3.2.4 Drawdown Certificate and Engineer's
Certificate. (i) At least ten (10) Banking Days prior to each Construction
Credit Event, Borrower shall have provided Agent with a certificate, dated the
date of the proposed occurrence of such Construction Credit Event and signed by
Borrower, substantially in the form of Exhibit C-5, and (ii) at least four (4)
Banking Days prior to each Construction Credit Event, the Independent Engineer
shall have provided Agent with a certificate of the Independent Engineer,
substantially in the form of Exhibit C-6.
3.2.5 Amount. Construction Loans shall be in such
amounts as shall ensure that uncommitted funds remaining in the Construction
Account shall be disbursed to the greatest extent possible, given the
requirements of Section 2.1.1(b)(ii).
3.2.6 Title Policy Endorsement. Borrower shall
provide, or Agent shall be adequately assured that the Title Insurer is
committed at the time of each Construction Credit Event to issue, to Agent a
date-down endorsement of the Title Policy to the date of such Construction
Credit Event, insuring the continuing first priority of the Deed of Trust
(subject only to Permitted Encumbrances) and otherwise in form and substance
reasonably satisfactory to Agent.
3.2.7 Lien Releases. If requested by Agent and
subject to Borrower's right to contest liens as described in the definition of
"Permitted Liens," Borrower shall have delivered to Agent duly executed
acknowledgments of payments and releases of mechanics' and materialmen's liens,
in form satisfactory to Agent, from each Contractor for all work, services and
materials, including equipment and fixtures of all kinds, done, previously
performed or furnished for the construction of the Project, and in respect of
which Borrower has requested payment; provided, however, that such releases may
be conditioned upon receipt of payment with
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respect to work, services and materials to be paid for with the proceeds of the
requested Construction Loan or other Borrowing.
3.2.8 Applicable Permits. Except as disclosed in
Exhibit G-3, all Applicable Permits and Applicable Third Party Permits with
respect to the construction and operation of the Project required to have been
obtained by Borrower or any Major Project Participant by the date of such
Construction Credit Event from any Governmental Authority shall have been
issued and be in full force and effect and not subject to current legal
proceedings or to any unsatisfied conditions that could reasonably be expect to
allow material modification or revocation, and all applicable appeal periods
with respect thereto shall have expired. With respect to any of the Permits
not yet obtained and listed in Part II(A) or II(B) of Exhibit G-3, no facts or
circumstances exist which indicate that any such Permit will not be timely
obtainable without material difficulty, expense or delay by Borrower or the
applicable Major Project Participant, respectively, prior to the time that it
becomes an Applicable Permit or Applicable Third Party Permit, as applicable.
Except as disclosed in Exhibit G-3, the Permits which have been obtained by the
Borrower or any Major Project Participant shall not be subject to any
restriction, condition, limitation or other provision that could reasonably be
expected to have a Material Adverse Effect.
3.2.9 Equity Contributions. Borrower shall be in
compliance with Section 5.18.
3.2.10 Additional Documentation. With respect to
Additional Project Documents and Applicable Permits entered into or obtained,
transferred or required (whether because of the status of the construction or
operation of the Project or otherwise) since the date of the most recent
Construction Credit Event, there shall be redelivery of such matters as are
described in Sections 3.1.1 through 3.1.4 and 3.1.6 to the extent applicable to
such Additional Project Documents or Applicable Permits and, if reasonably
requested by Agent, Sections 3.1.8 and 3.1.20 from the counterparty to such
Additional Project Document.
3.2.11 Acceptable Work; No Liens. All work that has
been done on the Project shall have been done in a good and workmanlike manner
and in accordance with the Construction Contracts and Prudent Utility Practices
and there shall not have been filed with or served upon Borrower with respect
to the Project or any part thereof notice of any Lien, claim of Lien or
attachment upon or claim affecting the right to receive payment of any of the
moneys payable to any of the Persons named on such request which has not been
released by payment or bonding or otherwise or which will not be released with
the payment of such obligation out of such Construction Loan or other
Borrowing, other than Permitted Liens.
3.2.12 Casualty. If at the time of any Construction
Credit Event, the Project shall have been materially injured or damaged by
flood, fire or other casualty, Agent shall have received insurance proceeds or
money or other assurances sufficient in the reasonable judgment of Agent and
the Independent Engineer to assure restoration and Completion prior to the
Construction Loan Maturity Date and each of the conditions set forth in Section
7.11.3 has been satisfied.
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3.2.13 Absence of Litigation. No action, suit,
proceeding or investigation shall have been instituted against Borrower, any
Partner or the Project which could reasonably be expected to have a Material
Adverse Effect, except as approved by Agent with the consent of the Majority
Banks.
3.2.14 Insurance. Insurance complying with the
requirements of Section 5.19 shall be in effect, and upon the request of Agent
evidence thereof shall be provided to Agent.
3.2.15 Key Personnel. The condition set forth in
Section 3.1.33 continues to be satisfied as of the date of the Construction
Credit Event.
3.2.16 Available Construction Funds. Available
Construction Funds shall not be less than the aggregate unpaid amount required
to cause the Completion Date to occur in accordance with all Legal
Requirements, the Construction Contracts and the Phillips Documents, prior to
the Date Certain and to pay or provide for all anticipated non-construction
costs, all as set forth in the Project Budget.
3.3 Conditions Precedent to Term-Conversion. No
Construction Loans shall Term-Convert unless the following conditions shall
have been satisfied:
3.3.1 Payment of Obligations. Borrower shall have
paid to Agent the principal amount of the Construction Loans outstanding which
will not be Term-Converted to Term Loans as provided in Section 2.1.2(a) plus
all interest due and owing on the Construction Loans and all other Obligations
of Borrower due and owing to Agent and the Banks hereunder or under the other
Credit Documents.
3.3.2 Final Drawing. Immediately prior to
Term-Conversion, Borrower shall have requested (in accordance with the terms of
this Article 3) a Construction Loan (the "Final Drawing") to be applied in
accordance with Section 7.1.4, in the amount, if any, of the remaining Total
Construction Loan Commitment up to the sum of (a) an amount sufficient for
completion of the Punch List and payment of other Project Costs through Final
Completion, determined by Borrower and approved by Agent in consultation with
Independent Engineer, (b) the amount required to be funded into the Emissions
Offsets Reserve Account at Term-Conversion, (c) the amounts required to be
funded into the Fuel Supply Reserve Account at Term-Conversion and (d) the
amount required to be funded into the Debt Service Reserve Account at
Term-Conversion.
3.3.3 Certificates of Occupancy. Delivery to
Agent, in form and substance satisfactory to Agent, of:
(a) Evidence that all work requiring
inspection by municipal and other Governmental Authorities having jurisdiction
has been duly inspected and approved by such authorities, that a final
certificate of occupancy or a certificate of final completion has been issued
for the Project, that Borrower has duly recorded a notice of completion for the
Project, that all
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parties performing such work have been or will be paid for such work, and that
no mechanics' and/or materialmen's liens or application therefor have been
filed and all applicable filing periods for any such mechanics' and/or
materialmen's liens have expired; provided, however, that in the event Borrower
delivers to agent either (i) a policy of title insurance or endorsement
thereto, in form and substance satisfactory to Agent, insuring against loss
arising by reason of any mechanics' or materialmen's lien gaining priority over
the Deed of Trust or (ii) a bond, in form and substance satisfactory to Agent,
in the amount of all payments owed to any contractor, subcontractor or any
other person as to whom the filing periods for mechanics' and materialmen's
liens have not expired, and covering Borrower's liability to such contractors,
subcontractors or other persons, Agent shall waive the applicable filing
periods referred to herein; and
(b) A certification by Construction
Manager and by Borrower and the Independent Engineer that Completion has been
achieved and that an appropriate "Permit to Operate" and "Certificate of
Occupancy" for the Project have been issued to Borrower or that Borrower and
Agent know of no reason why such certificates will not be issued when and as
needed.
3.3.4 Completion. Completion shall have occurred.
3.3.5 Equity Contributions. Borrower shall be in
compliance with Section 5.18.
3.3.6 Annual Budget. Agent shall have received the
initial Annual Operating Budget as required under Section 5.15.2.
3.3.7 Insurance. Insurance complying with the
requirements of Section 5.19 shall be in effect, and upon the request of Agent
evidence thereof shall be provided to Agent.
3.3.8 Reserve Accounts. Borrower shall have
deposited into (a) the Emissions Offsets Reserve Account, all funds required
under Section 7.4, (b) the Fuel Supply Reserve Account, all funds required
under Section 7.5 and (c) the Debt Service Reserve Account, all funds required
under Section 7.6.
3.3.9 Power Marketing Security Agreement. Borrower
shall have entered a security agreement with Power Marketer substantially in
the form of Exhibit D-4, with such changes to the description of collateral
therein as is necessary to provide Borrower with a first priority lien in the
Power Marketing Depository Account and such other changes as may be approved by
Agent (the "Power Marketing Security Agreement").
3.4 Conditions Precedent to Each Credit Event. The
obligation of the Banks to effect or permit each Credit Event is subject to the
further conditions that, on the date such Credit Event is to occur, the
following shall be true and correct:
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3.4.1 Representations and Warranties True and
Correct. Each representation and warranty set forth in Article 4 is true and
correct as if made on such date, unless such representation or warranty
expressly relates solely to another time.
3.4.2 No Event of Default or Inchoate Default. No
Event of Default or Inchoate Default has occurred and is continuing or will
result from such Credit Event.
3.4.3 Operative Documents, Applicable Permits and
Applicable Third Party Permits in Effect. Each Credit Document, Project
Document, Additional Project Document, Applicable Permit and Applicable Third
Party Permit remains in full force and effect and no material defaults have
occurred thereunder.
3.4.4 No Material Adverse Effect. No event or
circumstance having a Material Adverse Effect has occurred since the Closing
Date (except as is no longer continuing).
3.5 Conditions Precedent to Initial Distribution.
Borrower's right to effect the initial distribution as provided in Waterfall
Level 11 is subject to the prior satisfaction of each of the following
conditions (unless waived in writing by Agent with the consent of the Required
Banks):
3.5.1 Term-Conversion. Term-Conversion shall have
occurred.
3.5.2 Revised Base Case Projections. Borrower
shall have delivered to Agent a current set of Adjusted Base Case Projections
if so requested under Section 5.16.
3.5.3 Delivery of Documents. Delivery to Agent on
or after the date of Term-Conversion, in form and substance satisfactory to
Agent, of such date-down opinions, resolutions, certificates and other evidence
as Agent may reasonably request to insure Agent's satisfaction on such date
with the matters covered in Sections 3.1.8 (with respect solely to Borrower),
3.1.6, 3.1.10, 3.1.17 and 3.1.19.
3.5.4 Applicable Permits and Applicable Third Party
Permits. Borrower shall have obtained or caused to be obtained and delivered
to Agent all Applicable Permits, satisfactory in form and substance to Agent,
together with copies of each such Applicable Permit and a certificate of an
authorized officer of Borrower certifying that all such Permits have been
obtained. Each Major Project Participant shall have obtained or caused to be
obtained all Applicable Third Party Permits applicable to such Person,
satisfactory in form and substance to Borrower and Agent, and Borrower shall
deliver or cause to be delivered to Agent copies or other evidence of each such
Applicable Third Party Permit and a certificate of an authorized officer of
Borrower certifying that all such Applicable Third Party Permits have been
obtained. Except as disclosed in Exhibit G-3, all Applicable Permits and
Applicable Third Party Permits shall be in full force and effect, not subject
to any then current legal proceeding or to any unsatisfied condition that could
reasonably be expected to allow material modification or revocation, and all
applicable appeal periods with respect thereto shall have expired.
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3.5.5 A.L.T.A. Surveys. Agent shall have received
as-built A.L.T.A. surveys of the Site and the Easements, reasonably
satisfactory in form and substance to Agent and the Title Insurer, certified to
Agent as to completeness and accuracy as of not more than four weeks prior to
Term-Conversion by Weisser Engineering Co. or another licensed surveyor
reasonably satisfactory to Agent, showing (a) as to the Site, the exact
location and dimensions thereof, including the location of all means of access
thereto and all easements relating thereto and showing the perimeter within
which all foundations are located; (b) as to the Easements, the exact location
and dimensions thereof, including the location of all means of access thereto,
and all improvements or other encroachments in or on the Easements; (c) the
location and dimensions of all improvements, fences or encroachments located in
or on the Site or the Easements; (d) that the location of the Project does not
encroach on or interfere with adjacent property or existing easements or other
rights (whether on, above or below ground), and that there are no gaps, gores,
projections, protrusions or other survey defects; (e) whether the Site or any
portion thereof is located in a special earthquake or flood hazard zone; and
(f) that there are no other matters that could reasonably be expected to be
disclosed by a survey constituting a defect in title other than Permitted
Encumbrances.
3.5.6 Term Loan Title Policy. Agent shall have
received (a) a lender's A.L.T.A. policy of title insurance, together with such
endorsements as are reasonably required by Agent and are obtainable in the
State of Texas at reasonable costs, in the amount of the aggregate principal
amount of the Total Term Loan Commitment at the Conversion Date, issued by the
Title Insurer, in form and substance and with such reinsurance as is reasonably
satisfactory to Agent, and insuring Agent as to all matters described in
Section 3.1.26, the continued first priority of the Lien on the Mortgaged
Property evidenced by the Deed of Trust and as to such other matters as Agent
may reasonably request, and containing only Permitted Encumbrances, such
Permitted Liens as are junior and subordinate to the Deed of Trust and any
other exceptions relating to the boundaries of the Site, encroachments and
matters disclosed or discoverable by a survey or inspection as are acceptable
to Agent in its sole discretion or (b) an endorsement to the A.L.T.A. Policy
delivered to Agent pursuant to Section 3.1.26 hereof reasonably satisfactory to
Agent reflecting the items referred to above (such policy and endorsements, or
endorsement, being referred to as the "Term Loan Title Policy").
3.5.7 Power Marketing. Either of the following has
occurred: (i) Borrower has entered into one or more Distribution Threshold
Power Sales Agreements, covering, in the aggregate, at least 75 MW of firm
energy and capacity or (ii) the Project's Four-Quarter Average Debt Service
Coverage Ratio has equaled or exceeded, for five (5) consecutive calendar
quarters, 90% of the annual Debt Service Coverage Ratios for the year of
calculation set forth in the Base Case Project Projections in effect as of the
Closing Date for such five (5) consecutive calendar quarters.
3.6 No Approval of Work. The making of any Loan
hereunder shall not be deemed an approval or acceptance by Agent or the Banks
of any work, labor, supplies, materials or equipment furnished or supplied with
respect to the Project.
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3.7 Waiver of Funding; Adjustment of Drawdown Requests.
Notwithstanding the foregoing, the Required Banks, without waiving any of the
Banks' rights hereunder, shall have the right to effect a Credit Event
hereunder without full compliance by Borrower with the conditions described in
this Article 3. In the event Agent determines that an item or items listed in
a Drawdown Certificate as a Project Cost is not properly included in such
Drawdown Certificate, Agent may in its reasonable discretion cause to be made a
Loan or Loans in the amount requested in such Drawdown Certificate less the
amount of such item or items or may reduce the amount of Loans made pursuant to
any subsequent Drawdown Certificate. In the event that Borrower prevails in
any dispute as to whether such Project Costs were properly included in such
Drawdown Certificate, Loans in the amount requested but not initially made
shall forthwith be made.
ARTICLE 4 - REPRESENTATIONS AND WARRANTIES
Borrower makes the following representations and warranties
to and in favor of Agent and the Banks as of the Closing Date and as of the
date of each Credit Event. All of these representations and warranties shall
survive the Closing Date and the making of the Loans:
4.1 Organization.
4.1.1 Borrower (a) is a limited partnership duly
constituted, validly existing and in good standing under the laws of the State
of Delaware and (b) is duly qualified, authorized to do business and in good
standing in the States of California and Texas and in each other jurisdiction
where the character of its properties or the nature of its activities makes
such qualification necessary. Borrower has all requisite partnership power and
authority to own or hold under lease and operate the property it purports to
own or hold under lease and to carry on its business as now being conducted and
as now proposed to be conducted in respect of the Project. On the Closing
Date, (i) CPC is the sole general partner of Borrower and CTC is the sole
limited partner of Borrower and (ii) the sole direct owners of the Partners are
the specific Persons identified by name under the definition of "Shareholders".
4.1.2 CPC (a) is a corporation duly organized and
validly existing and in good standing under the laws of the State of Delaware
with all requisite corporate power and authority under the laws of the State of
Delaware to enter into the Partnership Agreement and as the general partner of
Borrower to perform its obligations thereunder and to consummate the
transactions contemplated thereby, (b) is duly qualified, authorized to do
business and in good standing in the State of Texas and each other jurisdiction
where the character of its properties or the nature of its activities makes
such qualification necessary, (c) has the corporate power (i) to carry on its
business as now being conducted and as proposed to be conducted by it, (ii) to
execute, deliver and perform each Operative Document to which it is a party, in
its individual capacity, (iii) to take all action as may be necessary to
consummate the transactions contemplated thereunder and (iv) to grant the liens
and security interest provided for in the Pledge and Security Agreement to
which it is a party and (d) has the power and authority under the Partnership
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Agreement to execute and deliver, on behalf of Borrower, each Operative
document to which Borrower is a party.
4.2 Authorization; No Conflict. Borrower has duly
authorized, executed and delivered each Operative Document to which Borrower is
a party and neither Borrower's execution and delivery thereof nor its
consummation of the transactions contemplated thereby nor its compliance with
the terms thereof (a) does or will contravene the Partnership Agreement, the
Articles or Certificate of Incorporation or bylaws of any Partner or any other
Legal Requirement applicable to or binding on Borrower or any of its
properties, (b) does or will contravene or result in any breach of or
constitute any default under, or result in or require the creation of any Lien
(other than Permitted Liens) upon any of its property under, any agreement or
instrument to which it is a party or by which it or any of its properties may
be bound or affected or (c) does or will require the consent or approval of any
Person which has not already been obtained.
4.3 Enforceability. Each of the Operative Documents to
which Borrower is a party is a legal, valid and binding obligation of Borrower
enforceable against Borrower, in accordance with its terms, except to the
extent that enforceability may be limited by applicable bankruptcy, insolvency,
moratorium, reorganization or other similar laws affecting the enforcement of
creditors' rights or by the effect of general equitable principles. None of
the Operative Documents to which Borrower is a party has been amended or
modified except in accordance with this Agreement.
4.4 Compliance with Law. There are no violations by
Borrower, any Partner or, to Borrower's knowledge, any Shareholder of any Legal
Requirement which could reasonably be expected to have a Material Adverse
Effect. Except as otherwise have been delivered to Agent, no notices of
violation of any Legal Requirement relating to the Project or the Site have
been issued, entered or received by Borrower, any Partner or, to Borrower's
knowledge, any Shareholder.
4.5 Business, Debt, Contracts, Joint Ventures Etc.
4.5.1 Neither any Partner nor Borrower has
conducted any business other than the business contemplated by the Operative
Documents, has any outstanding Debt or other material liabilities other than
pursuant to or allowed by the Operative Documents, and is not a party to or
bound by any material contract other than the Operative Documents to which it
is a party.
4.5.2 Borrower is not a general partner or a
limited partner in any general or limited partnership or a joint venturer in
any joint venture.
4.5.3 Neither Borrower nor any Partner thereof has
any subsidiaries.
4.6 Adverse Change. To the best of Borrower's knowledge,
there has occurred no material adverse change in the Project Budget, Project
Schedule or Base Case Project
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Projections, in the economics or feasibility of constructing and/or operating
the Project, or in the financial condition, business or property of any Major
Project Participant, or any other event or circumstance which is reasonably
likely to have a Material Adverse Effect (a) as of the Closing Date, since
April 22, 1996 and (b) after the Closing Date, except as disclosed to Agent in
writing at the time the representation in this Section 4.6 is being made, since
the Closing Date.
4.7 Investment Company Act, Etc. Neither Borrower nor
any Partner is an investment company or a company controlled by an investment
company, within the meaning of the Investment Company Act of 1940, and neither
Borrower nor any Partner is or has been determined by the Securities and
Exchange Commission or any other Governmental Authority to be subject to, or
not exempt from, regulation under PUHCA or the FPA (other than as provided by
PURPA).
4.8 ERISA. Either (a) there are no ERISA Plans for
Borrower or any member of the Controlled Group or (b) Borrower and each member
of the Controlled Group have fulfilled their obligations (if any) under the
minimum funding standards of ERISA and the Code for each ERISA Plan in
compliance in all material respects with the currently applicable provisions of
ERISA and the Code and have not incurred any liability to the PBGC or an ERISA
Plan under Title IV of ERISA (other than liability for premiums due in the
ordinary course). Assuming that the credit extended hereunder does not involve
the assets of any employee benefit plan subject to ERISA, neither the
execution of this Agreement nor the consummation of the transactions
contemplated hereby will involve a "prohibited transaction" within the meaning
of Section 406 of ERISA or Section 4975 of the Code which is not exempt under
Section 408 of ERISA or under Section 4975(d) of the Code.
4.9 Permits.
4.9.1 There are no Permits under existing law as
the Project is currently designed that are or will become Applicable Permits
other than the Applicable Permits described in Exhibit G-3 hereto. Each
Applicable Permit listed in Part I(A) of Exhibit G-3 is in full force and
effect, and except as disclosed therein, is not subject to any current legal
proceeding or to any unsatisfied condition that could reasonably be expected to
have a Material Adverse Effect, and all applicable appeal periods with respect
thereto have expired. Each Permit listed in Part II(A) of Exhibit G-3 is of a
type that is routinely granted upon application and that would not normally be
obtained before contemplated by Borrower. No fact or circumstance exists, to
Borrower's knowledge, which indicates that any Permit identified in Part II(A)
of Exhibit G-3 shall not be timely obtainable without material difficulty,
expense or delay by Borrower before it becomes an Applicable Permit. Borrower
is in compliance in all material respects with all Applicable Permits.
4.9.2 There are no Permits under existing law as
the Project is currently designed that are or will become an Applicable Third
Party Permits other than the Applicable Third Party Permits described in
Exhibit G-3 hereto (other than those, the failure of which to obtain could not
reasonably be expected to have a Material Adverse Effect). Each Applicable
Third Party Permit listed in Part I(B) of Exhibit G-3 is in full force and
effect, and except as
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disclosed therein, is not subject to current legal proceeding or to any
unsatisfied condition that could reasonably be expected to have a Material
Adverse Effect, and all applicable appeal periods with respect thereto have
expired. No fact or circumstance exists, to Borrower's knowledge, which
indicates that any Permit identified in Part II(B) of Exhibit G-3 shall not be
timely obtainable without material difficulty, expense or delay by the
applicable Major Project Participant before it becomes an Applicable Third
Party Permit. To the best knowledge of Borrower, each Major Project
Participant is in compliance in all material respects with its respective
Applicable Third Party Permits, each other Major Project Participant possesses
all licenses, franchises, patents, copyrights, trademarks and trade names, or
rights thereto necessary to perform its duties under the Operative Documents to
which it is a party, and such Person is not in violation of any valid rights of
others with respect to any of the foregoing which could reasonably be expected
to have a Material Adverse Effect.
4.10 Qualifying Facility. The Project qualifies as, and,
upon and following the Completion Date, is a Qualifying Facility.
4.11 Hazardous Substance.
4.11.1 Borrower has previously delivered to Agent
the Environmental Reports and Agent acknowledges receipt thereof. Except as
set forth in Exhibit G-8: (a) neither Borrower nor any Partner nor any
Shareholder (the "Subject Companies"), with respect to the Site, Improvements
or other Mortgaged Property, is or has in the past been in violation of any
Hazardous Substance Law which violation could reasonably be expected to result
in a material liability to any of the Subject Companies or their respective
properties and assets or in an inability of Borrower to perform its obligations
under the Operative Documents; (b) none of the Subject Companies nor, to the
best knowledge of the Partners and Borrower, any third party has used,
released, discharged, generated, manufactured, produced, stored, or disposed of
in, on, under, or about the Site, Improvements or other Mortgaged Property, or
transported thereto or therefrom, any Hazardous Substances that could
reasonably be expected to subject the Banks to liability or the Subject
Companies to liability, under any Hazardous Substance Law; (c) there are no
underground tanks, whether operative or temporarily or permanently closed,
located on the Site, Improvements or other Mortgaged Property; (d) there are no
Hazardous Substances used, stored or present at, on or, to the best knowledge
of Borrower and the Partners after due inquiry, near the Site, Improvements or
other Mortgaged Property, except in compliance with Hazardous Substance Laws
and other Legal Requirements or as disclosed in the Environmental Reports; and
(e) to the best knowledge of Borrower and the Partners after due inquiry, there
neither is nor has been any condition, circumstance, action, activity or event
that could reasonably be expected to be a material violation by the Subject
Companies of any Hazardous Substance Law, or to result in liability to the
Banks or material liability to the Subject Companies under any Hazardous
Substance Law.
4.11.2 Except as set forth on Exhibit G-7 or Exhibit
G-8, there is no pending or, to the best knowledge of Borrower, threatened,
action or proceeding by any Governmental Authority (including, without
limitation, the Texas Natural Resource Conservation
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Commission and the U.S. Environmental Protection Agency) or any
non-governmental third party with respect to the presence or Release of
Hazardous Substances in, on, from or to the Site, Improvements or other
Mortgaged Property.
4.11.3 Neither Borrower nor any Partner nor
Shareholder has knowledge of any past or existing violations of any Hazardous
Substances Laws by any Person relating in any way to the Site, Improvements or
other Mortgaged Property.
4.12 Litigation. Except as set forth on Exhibit G-7,
there are no pending or, to the best knowledge of Borrower, threatened actions
or proceedings of any kind, including actions or proceedings of or before any
Governmental Authority, to which Borrower, any Partner, any Shareholder, or, to
the best knowledge of Borrower, any other Major Project Participant or the
Project is a party or is subject, or by which any of them or any of their
properties or the Project are bound, which if adversely determined to or
against Borrower, any other Major Project Participant or the Project could
reasonably be expected to have a Material Adverse Effect.
4.13 Labor Disputes and Acts of God. Neither the business
nor the properties of Borrower, any Partner, any Shareholder, or, to the best
knowledge of Borrower, any other Major Project Participant are affected by any
fire, explosion, accident, strike, lockout or other labor dispute, drought,
storm, hail, earthquake, embargo, act of God or of the public enemy, or other
casualty (whether or not covered by insurance), which could reasonably be
expected to have a Material Adverse Effect.
4.14 Project Documents.
4.14.1 Copies of all of the Project Documents in
effect as of such date have been delivered to Agent by Borrower. Except as has
been previously disclosed in writing to Agent, as of the Closing Date none of
the Project Documents has been amended, modified or terminated.
4.14.2 To Borrower's knowledge, the representations
and warranties of the Major Project Participants contained in the Operative
Documents other than this Agreement are true and correct.
4.15 Disclosure. Neither this Agreement nor any
certificate or other documentation furnished to Agent, or to any consultant
submitting a report to Agent, by or, to the knowledge of Borrower, on behalf of
Borrower in connection with the transactions contemplated by this Agreement,
the other Project Documents or the design, description, testing or operation of
the Project, contains any untrue statement of a material fact or omits to state
a material fact necessary in order to make the statements contained herein or
therein not misleading under the circumstances in which they were made at the
time such statements are made. As of the Closing Date, there is no fact known
to Borrower which has had or could reasonably be expected to have a Material
Adverse Effect which has not been set forth in this Agreement or in the other
documents, certificates and written statements furnished to Agent and/or the
Independent
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Engineer, by or on behalf of Borrower prior to the Closing Date in connection
with the transactions contemplated hereby. The documentation furnished to
Agent and to the Independent Engineer on or prior to the Closing Date, as the
case may be, taken as a whole, including without limitation written updated or
supplemented information, is true and correct in all material respects and all
such documentation does not omit to state any fact which would have a Material
Adverse Effect.
4.16 Private Offering by Borrower. Assuming that the
Banks are acquiring the Notes for investment purposes only, and not for
purposes of resale or distribution thereof except for assignments or
participations as provided in Sections 10.13 and 10.14, no registration of the
Notes under the Securities Act of 1933, as amended, or under the securities
laws of the State of Texas or New York is required in connection with the
offering, issuance and sale of the Notes hereunder. Neither Borrower nor
anyone acting on its behalf has taken, or will take, any action which would
subject the issuance or sale of the Notes to Section 5 of the Securities Act of
1933, as amended.
4.17 Taxes. Borrower and each Partner has filed all
federal, state and local tax returns that it is required to file, has paid all
taxes it is required to pay to the extent due (other than those taxes that it
is contesting in good faith and by appropriate proceedings, with adequate,
segregated reserves or other security reasonably acceptable to Agent
established for such taxes) and, to the extent such taxes are not due, has
established reserves that are adequate for the payment thereof and are required
by GAAP. For federal income tax purposes, Borrower is a partnership and not an
association taxed as a corporation.
4.18 Governmental Regulation. None of Borrower, any
Partner, Agent, or the Banks, nor any Affiliate of any of them will, solely as
a result of the construction, ownership, leasing or operation of the Project,
the sale of electricity therefrom or the entering into any Operative Document
or any transaction contemplated hereby or thereby, be subject to, or not exempt
from, regulation under the FPA or PUHCA or under state laws and regulations
respecting the rates or the financial or organizational regulation of electric
utilities. Borrower is not subject to regulation under any Governmental Rule
as to securities, rates or financial or organizational matters that would
preclude any Loans, or the incurrence by Borrower of any of the Obligations or
the execution, delivery and performance by Borrower of the Operative Documents.
Borrower will not be deemed by any Governmental Authority having jurisdiction
to be subject to financial, organizational or rate regulation as an "electric
utility," "electric corporation," "electrical company," "public utility,"
"public utility holding company" or any similar entity under any existing law,
rule or regulation of any Governmental Authority.
4.19 Regulation U, Etc. Borrower is not engaged
principally, or as one of its principal activities, in the business of
extending credit for the purpose of purchasing or carrying margin stock (as
defined in Regulations G, T, U or X of the Federal Reserve Board), and no part
of the proceeds of the Loans or the Project Revenues will be used by Borrower
to purchase or carry any such margin stock or to extend credit to others for
the purpose of purchasing or carrying any such margin stock.
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4.20 Project Budget; Projections; Commercial Operation
Date. Borrower has prepared the Project Budget and the Base Case Project
Projections and is responsible for developing the assumptions on which the
Project Budget and the Base Case Project Projections are based; and the Project
Budget and the Base Case Project Projections (a) are based on reasonable
assumptions as to all legal and factual matters material to the estimates set
forth therein, (b) as of the Closing Date are consistent with the provisions of
the Project Documents and (c) indicate that the estimated Project Costs will
not exceed funds available to pay Project Costs. In the reasonable opinion of
Borrower, as of the Closing Date the textual material accompanying the Base
Case Project Projections discloses all information reasonably necessary for an
understanding of the Base Case Project Projections, and does not contain any
material misstatements or omit any information which, in conjunction with other
information given, would be necessary to make such information not materially
misleading.
4.21 Financial Statements. The financial statements of
Borrower, the Partners, Calpine, and Power Marketer delivered pursuant to
Section 3.1.20 and Section 5.5 are true, complete and correct and fairly
present the financial condition of each such Person as of the date thereof.
Such financial statements have been prepared in accordance with GAAP. Neither
Borrower, the Partners, Calpine, or Power Marketer has any material
liabilities, direct or contingent, except as has been disclosed in such
financial statements.
4.22 Existing Defaults. Borrower is not in default under
any material term of any Operative Document or any agreement relating to any
obligation of Borrower for or with respect to borrowed money, and to the best
of Borrower's knowledge, no other party to any Project Document is in default
thereunder.
4.23 No Default. No Event of Default or Inchoate Default
has occurred or is existing.
4.24 Offices, Location of Collateral.
4.24.1 The chief executive office or chief place of
business (as such term is used in Article 9 of the Uniform Commercial Code as
in effect in the State of Texas from time to time) of Borrower is located at
San Jose, California. Borrower's federal employer identification number is
77-0444630.
4.24.2 All of the Collateral (other than the Accounts
and general intangibles), including the Mortgaged Property is, or when
installed pursuant to the Project Documents will be, located on the Site or the
Easements or at the address set forth in Section 4.24.1.
4.24.3 Borrower's books of accounts and records are
located at 50 West San Fernando Street, San Jose, California 95113.
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4.25 Title and Liens. Borrower has good, marketable and
insurable title to the Project, and all of the Collateral relating to the
Project, and good, marketable and insurable title to, or as applicable, a
leasehold estate in, the Site and the Easements (except that title to certain
of the Easements which are licenses may not be insurable), in each case free
and clear of all Liens, encumbrances or other exceptions to title other than
Permitted Liens. The Lien of the Collateral Documents constitutes a valid and
subsisting first priority lien of record on all the Mortgaged Property
described in the Deed of Trust and a first priority perfected security interest
in all the personal property described in the Collateral Documents, subject to
no Liens except Permitted Encumbrances.
4.26 Trademarks. Borrower owns or has the right to use
all patents, trademarks, service marks, trade names, copyrights, licenses and
other rights, which are necessary for the operation of its business. Nothing
has come to the attention of Borrower to the effect that (a) any material
product, process, method, substance, part or other material presently
contemplated to be sold by or employed by Borrower in connection with its
business will infringe any patent, trademark, service mark, trade name,
copyright, license or other right owned by any other Person, (b) there is
pending or threatened any claim or litigation against or affecting Borrower
contesting its right to sell or use any such product, process, method,
substance, part or other material or (c) there is, or there is pending or
proposed, any patent, invention, device, application or principle or any
statute, law, rule, regulation, standard or code relating to the use of
technology or intellectual property by Borrower which could reasonably have a
Material Adverse Effect.
4.27 Collateral. The security interests granted to Agent
pursuant to the Collateral Documents in the Collateral (a) constitute as to
personal property included in the Collateral and, with respect to subsequently
acquired personal property included in the Collateral, will constitute, a
perfected security interest under the UCC to the extent a security interest can
be perfected by filing or, in the case of the Accounts, by possession by or on
behalf of the secured party and (b) are, and, with respect to such subsequently
acquired property, will be, as to Collateral perfected under the UCC as
aforesaid, superior and prior to the rights of all third Persons now existing
or hereafter arising whether by way of mortgage, lien, security interests,
encumbrance, assignment or otherwise except for Phillips' rights under the
Ground Lease with respect to the Development and Construction Easements upon
the Commercial Operation Date or earlier termination of the Ground Lease and
with respect to the Project upon Phillips' exercise of the Project Purchase
Option or upon surrender or termination of the Ground Lease. Except to the
extent possession of portions of the Collateral is required for perfection, all
such action as is necessary has been taken to establish and perfect Agent's
rights in and to the Collateral to the extent Agent's security interest can be
perfected by filing, including any recording, filing, registration, giving of
notice or other similar action. As of the Closing Date, no filing,
recordation, re- filing or re-recording other than those listed on Exhibit D-11
hereto is necessary to perfect and maintain the perfection of the interest,
title or Liens of the Collateral Documents, and on the Closing Date all such
filings or recordings will have been made to the extent Agent's security
interest can be perfected by filing. Borrower has properly delivered or caused
to be delivered to Agent all Collateral that requires perfection of the Lien
and security interest described above by possession.
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4.28 Sufficiency of Project Documents.
4.28.1 Other than those that can be reasonably
expected to be commercially available when and as required, the services to be
performed, the materials to be supplied and the real property interests, the
Easements and other rights granted pursuant to the Project Documents:
(a) comprise all of the property
interests necessary to secure any right material to the acquisition, leasing,
development, construction, installation, completion, operation and maintenance
of the Project in accordance with all Legal Requirements and in accordance with
the Project Schedule, all without reference to any proprietary information not
owned by Borrower;
(b) are sufficient to enable the Project
to be located, constructed and operated on the Site and the Easements; and
(c) provide adequate ingress and egress
from the Site for any reasonable purpose in connection with the construction
and operation of the Project.
4.28.2 There are no services, materials or rights
required for the construction or operation of the Project in accordance with
the Construction Contracts and the Base Case Project Projections other than
those that can reasonably be expected to be commercially available at the Site
on commercially reasonable terms consistent with the Project Budget and the
Base Case Project Projections.
4.29 Utilities. All utility services necessary for the
construction and the operation of the Project for its intended purposes are
available at the Project or will be so available as and when required upon
commercially reasonable terms consistent with the Project Budget, Project
Schedule and the Base Case Project Projections.
4.30 Roads/Transmission Line.
4.30.1 All roads necessary for the construction and
full utilization of the Project for its intended purposes have either been
completed or the necessary rights of way therefor have been acquired.
4.30.2 All necessary easements, rights of way,
licenses, agreements and other rights for the construction, interconnection and
utilization of (a) the interconnection facilities (including the
interconnection to the HL&P grid) and (b) the Steam Line have been acquired.
4.31 Proper Subdivision. The Site has been properly
subdivided or entitled to exception therefrom, and for all purposes the Site
may be mortgaged, conveyed and otherwise dealt with as separate legal lots or
parcels.
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4.32 Flood Zone Disclosure. None of the Collateral
includes improved real property that is or will be located in an area that has
been identified by the Director of the Federal Emergency Management Agency as
an area having special flood hazards and in which flood insurance has been made
available under the National Flood Insurance Act of 1968, as amended.
ARTICLE 5 - COVENANTS OF THE BORROWER
Borrower covenants and agrees that so long as this Agreement
is in effect, it will:
5.1 Use of Proceeds and Project Revenues.
5.1.1 Proceeds. Unless otherwise applied by Agent
pursuant to this Agreement, deposit the proceeds of the Construction Loans in
the Construction Account, hold such proceeds as a trust fund for the payment of
Project Costs, and use them solely to pay Project Costs.
5.1.2 Revenues. Unless otherwise applied by Agent
pursuant to Articles 7 and 8, deposit all Project Revenues other than Insurance
Proceeds, Eminent Domain Proceeds and damage payments described in Section 7.13
received prior to Term-Conversion in the Construction Account for application
toward Project Costs and otherwise for application as set forth in Section 7.1,
deposit all Project Revenues other than Insurance Proceeds, Eminent Domain
Proceeds and damage payments described in Section 7.13 received after
Term-Conversion in the Revenue Account for application solely for the purposes
and in the order and manner provided in Section 7.2, and deposit all Insurance
Proceeds, Eminent Domain, proceeds and damage payments described in Section
7.13 received at any time in the Loss Proceeds Account for application solely
for the purposes, and in the order and manner, provided in Section 7.7.
5.2 Payment.
5.2.1 Credit Documents. Pay all sums due under
this Agreement and the other Credit Documents according to the terms hereof and
thereof.
5.2.2 Project Documents. Pay all obligations due
under the Project Documents, howsoever arising, as and when due and payable,
except (a) such as may be contested in good faith or as to which a bona fide
dispute may exist, provided that Agent is satisfied in its reasonable
discretion that non-payment of such obligation pending the resolution of such
contest or dispute will not in any way endanger or materially adversely affect
the Project, the Banks' Liens in the Collateral or Borrower or that provision
is made to the satisfaction of Agent in its reasonable discretion for the
posting of security (other than the Collateral) for or the bonding of such
obligations or the prompt payment thereof in the event that such obligation is
payable and (b) Borrower's trade payables which shall be paid in the ordinary
course of business.
5.3 Warranty of Title. Maintain (a) good, marketable and
insurable leasehold title to the Site and related Easements, subject only to
Permitted Liens, and (b) good, marketable
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and insurable title to all of its other respective properties and assets (other
than properties and assets disposed of in the ordinary course of business).
5.4 Notices. Promptly, upon acquiring notice or giving
notice, as the case may be, or obtaining knowledge thereof, give written notice
(with copies of any such underlying notices) to Agent of:
5.4.1 Any litigation pending or, to the knowledge
of Borrower, threatened against Borrower involving claims against Borrower or
the Project in excess of $100,000 in the aggregate per calendar year or
involving any injunctive, declaratory or other equitable relief, such notice to
include, if requested by Agent, copies of all papers filed in such litigation
and to be given monthly if any such papers have been filed since the last
notice given;
5.4.2 Any dispute or disputes which may exist
between Borrower and any Governmental Authority and which involve (a) claims
against Borrower which exceed $100,000 individually or $250,000 in the
aggregate per calendar year, (b) injunctive or declaratory relief, (c)
revocation, modification, failure to renew or the like of any Applicable Permit
or Applicable Third Party Permit or imposition of additional material
conditions with respect thereto, or (d) any Liens for taxes due but not paid;
5.4.3 Any Event of Default or Inchoate Default;
5.4.4 Any casualty, damage or loss, whether or not
insured, through fire, theft, other hazard or casualty, or any act or omission
of Borrower, its employees, agents, contractors, consultants or
representatives, or of any other Person if such casualty, damage or loss
affects Borrower or the Project, in excess of $100,000 for any one casualty or
loss or in the aggregate in any policy period;
5.4.5 Any cancellation or material change in the
terms, coverage or amounts of any insurance described in Exhibit K;
5.4.6 Any matter which has had, or, in Borrower's
reasonable judgment, could reasonably be expected to have, a Material Adverse
Effect, including any PUC or FERC proceedings affecting the Project which if
adversely determined, reasonably could be expected to have a Material Adverse
Effect;
5.4.7 Any contractual obligations incurred by
Borrower exceeding $100,000 per year in the aggregate for the Project, not
including any obligations incurred pursuant to the Credit Documents or the
Project Documents (excluding Additional Project Documents and the Partnership
Agreement) or any obligation contemplated in the approved Annual Operating
Budget;
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5.4.8 Any act by Borrower to become a surety,
guarantor, endorser or accommodation endorser for a third party other than
endorsement of negotiable instruments for collection purposes;
5.4.9 Any intentional withholding of compensation
to any Contractor, any engineer or Operator or any other Person under any
Construction Contract, or the O&M Agreement, or any other construction or
operating contract relating to the Project, other than retention provided by
the express terms of any such contracts;
5.4.10 Any termination or material default or notice
thereof (including any notice of default) under any Project Document;
5.4.11 Any events of force majeure or change orders
under any Construction Contract or other Project Documents and, to the extent
requested by Agent, copies of invoices or statements which are reasonably
available to Borrower under such Construction Contract, certified by an
authorized representative of Borrower, together with a copy of any supporting
documentation, schedule, data or affidavit delivered under the Construction
Contract or such other Project Document;
5.4.12 No later than the date upon which the
Independent Engineer is entitled to receive notice pursuant to any Construction
Contract of the proposed conduct of the initial Performance Tests under such
Construction Contract, promptly prior to the proposed conduct of any subsequent
Performance Tests pursuant to each such Construction Contract and promptly
prior to the conduct of any performance tests required under any other Project
Document, written notice of such proposed test;
5.4.13 Any (a) fact, circumstance, condition or
occurrence at, on, or arising from, the Site, Improvements, or other Mortgaged
Property that results in material noncompliance with any Hazardous Substance
Law or any Release of Hazardous Substances on or from the Site, Improvements or
other Mortgaged Property that has resulted or could reasonably be expected to
result in personal injury or material property damage or to have a Material
Adverse Effect, and (b) pending or, to Borrower's knowledge, threatened,
Environmental Claim against Borrower or to Borrower's knowledge any of its
Affiliates, contractors, lessees or any other Persons, arising in connection
with their occupying or conducting operations on or at the Project, the Site,
the Improvements or the other Mortgaged Property;
5.4.14 Promptly, but in no event later than 30 days
if consent of Agent or the Bank is required, and 15 days otherwise, prior to
the time any Person will become a partner of Borrower or the occurrence of any
other change in or transfer of ownership interests in Borrower or the Project,
notice thereof, which notice shall identify such partner and such partner's
interest in Borrower or shall describe, in reasonable detail, such other change
or transfer;
5.4.15 Any material notices delivered to or received
from, the parties to the Project Documents, including any Pricing Notices;
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5.4.16 Initiation of any condemnation proceedings
involving the Project or the Site or any portion thereof; and
5.4.17 Promptly, but in no event later than 15 days
after Borrower has knowledge of the execution and delivery thereof, a copy of
each Additional Project Document.
5.4.18 Promptly, but in no event later than 30 days
after the receipt thereof by Borrower, copies of (a) all Applicable Permits
obtained by Borrower or any Partner after the Closing Date, (b) any amendment,
supplement or other modification to any Applicable Permits received by Borrower
after the closing Date and (c) all material notices relating to the Project
received by Borrower from any Governmental Authority.
5.5 Financial Statements.
5.5.1 Unless Agent otherwise consents, deliver or
cause to be delivered to Agent, in form and detail reasonably satisfactory to
Agent:
(a) As soon as practicable and in any
event within 45 days after the end of the first, second and third quarterly
accounting periods of its fiscal year (commencing with the quarter ending March
31, 1997), an unaudited balance sheet of Borrower, the Partners, the
Shareholders, Calpine, Power Marketer, Fuel Supplier (or its parent
corporation) and HL&P (or its parent corporation) and Phillips as of the last
day of such quarterly period and the related statements of income, cash flows,
and partners' capital (where applicable) for such quarterly period and (in the
case of second and third quarterly periods) for the portion of the fiscal year
ending with the last day of such quarterly period, setting forth in each case
in comparative form corresponding unaudited figures from the preceding fiscal
year (such requirement may be satisfied with respect to Phillips, Shareholder,
Calpine, Fuel Supplier and HL&P (or Fuel Supplier's and HL&P's respective
parent corporations) by delivery of the appropriate Form 10-Q filed with the
Securities and Exchange Commission); and
(b) As soon as available but no later
than 120 days after the close of each applicable fiscal year, audited financial
statements of Borrower, the Partners, the Shareholders, Calpine, Power
Marketer, Phillips, and, to the extent reasonably available, the Fuel Supplier
and HL&P (or their respective parent corporations), including a statement of
equity, a balance sheet as of the close of such year, an income and expense
statement, reconciliation of capital accounts and a statement of sources and
uses of funds, all prepared in accordance with GAAP and in the case of audited
financial statements, certified by an independent certified public accountant
selected by the Person whose financial statements are being prepared and
satisfactory to Agent. Such certificate for Borrower, each Partner, each
Shareholder, Calpine, Power Marketer, Phillips, the Fuel Supplier and HL&P (or
their respective parent corporations) shall not be qualified or limited because
of restricted or limited examination by such accountant of any material portion
of the records of the applicable Person. Such requirement may be satisfied
with respect to Phillips, Shareholder, Calpine, Fuel Supplier and HL&P, (or
Fuel Supplier's and
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HL&P's respective parent corporations) by delivery of the appropriate Form 10-K
filed with the Securities and Exchange Commission.
5.5.2 Each time the financial statements are
delivered under Section 5.5.1(a) above for Borrower, the Partners, the
Shareholders, Calpine, Power Marketer (if an Affiliate of Borrower), cause to
be delivered, along with such financial statements, a certificate signed by a
Responsible Officer of such Person, certifying that such officer has made or
caused to be made a review of the transactions and financial condition of such
Person during the relevant fiscal period and that such review has not, to the
best of such Responsible Officer's knowledge, disclosed the existence of any
event or condition which constitutes an Event of Default or Inchoate Default,
or if any such event or condition existed or exists, the nature thereof and the
corrective actions that such Person has taken or proposes to take with respect
thereto, and also certifying that such Person is in compliance with all
applicable material provisions of each Credit Document to which such Person is
a party or, if such is not the case, stating the nature of such non-compliance
and the corrective actions which such Person has taken or proposes to take with
respect thereto.
5.6 Books, Records, Access. Maintain adequate books,
accounts and records with respect to Borrower and the Project and prepare all
financial statements required hereunder in accordance with GAAP and in
compliance with the regulations of any Governmental Authority having
jurisdiction thereof, and, subject to requirements of Governmental Rules and
safety requirements, after pre-scheduling with the Operator, permit employees
or agents of Agent and Independent Engineer at any reasonable times and upon
reasonable prior notice to inspect all of Borrower's properties, including the
Site, to examine or audit all of Borrower's books, accounts and records and
make copies and memoranda thereof and to witness the Performance Tests.
5.7 Compliance with Laws, Instruments, Etc. Promptly
comply, or cause compliance, in all material respects, with all Legal
Requirements, including Legal Requirements relating to pollution control,
environmental protection, equal employment opportunity or employee benefit
plans, ERISA Plans and employee safety, with respect to Borrower or the
Project, and make such alterations to the Project and the Site as may be
required for such compliance.
5.8 Reports.
5.8.1 Deliver to Agent on the last Banking Day of
each month prior to Final Completion in which no Loan is made (if any) a
certificate of an authorized officer of Borrower as to the matters required by
Section 3.2.4, substantially in the form of the Drawdown Certificate.
5.8.2 Deliver to Agent at such times as Agent may
reasonably request (but not more frequently than monthly) a report describing
in reasonable detail the progress of the construction of the Project since the
last prior report hereunder.
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5.8.3 Within 30 days following the completion of
the major foundations for the Project, provide to Agent a foundation survey
showing (a) the exact location and dimensions of such foundations, (b) that
such foundations comply with all applicable building and zoning codes and
set-back lines, and (c) that such foundations do not encroach or interfere with
existing property rights.
5.8.4 Deliver to Agent within 30 days of the end of
each month after Term-Conversion, a summary operating report which shall
include, with respect to the month most recently ended, (a) a monthly and
year-to-date numerical and narrative assessment of (i) the Project's compliance
with each material category in the Annual Operating Budget, (ii) electrical and
steam production and delivery, (iii) fuel deliveries and use, including heat
rate, (iv) plant and unit availability, including trips and scheduled and
unscheduled outages, (v) cash receipts and disbursements and cash balances,
including distributions to the Partners, debt service payments and balances in
the Accounts, (vi) maintenance activity, (vii) staffing changes with respect to
project or construction managers, (viii) casualty losses of value in excess of
$100,000, (ix) replacement of equipment of value in excess of $100,000 and (x)
material disputes with contractors, materialmen, suppliers or others and any
related claims against Borrower; (b) statistical data and reasonably detailed
commentary thereon; and (c) a comparison of year-to-date figures to
corresponding figures provided in the prior year.
5.8.5 Deliver to Agent within 60 days of the end of
each year a report setting forth a narrative summary describing and assessing
the Project's compliance with all Applicable Permits and Legal Requirements.
5.8.6 Provide to Agent promptly upon request such
reports, statements, lists of property, accounts, budgets, forecasts and other
information concerning the Project and, to the extent reasonably available, the
Major Project Participants and at such times as Agent shall reasonably require,
including such reports and information as are reasonably required by the
Independent Consultants.
5.8.7 Provide to Agent promptly upon receipt by
Borrower any material notices, information or reports provided by (a) Phillips
under the Energy Sales Agreement, (b) HL&P under the HL&P Agreements, (c) Power
Marketer under any Power Marketing Project Document or (d) any other purchaser
under a Power Purchase Document.
5.8.8 Within 30 days of the end of each fiscal
year, deliver to Agent a certificate, substantially in the Form of Exhibit L
hereto, and otherwise in form and substance satisfactory to Agent in
consultation with the Insurance Consultant, certifying that the insurance
requirements of Exhibit K have been implemented and are being complied with in
all material respects.
5.9 Existence, Conduct of Business, Properties, Etc.
Except as otherwise expressly permitted under this Agreement, (a) maintain and
preserve its existence as a Delaware limited partnership and all material
rights, privileges and franchises necessary or desirable in the
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normal conduct of its business, (b) perform (to the extent not excused by force
majeure events or the nonperformance of the other party and not subject to a
good faith dispute) all of its contractual obligations under the Operative
Documents to which it is party or by which it is bound, (c) maintain all
necessary Permits and licenses, including all Applicable Permits, with respect
to its business and the Project and cause all Major Project Participants to
maintain all Applicable Third-Party Permits, (d) at or before the time that any
Permit becomes an Applicable Permit, obtain such Permit, (e) at or before the
time that any Permit required to be obtained by a Major Project Participant
becomes an Applicable Third-Party Permit, cause the relevant third party to
obtain such Permit and (f) engage only in the business contemplated by the
Operative Documents.
5.10 Debt Service Coverage Ratios. As promptly as
practicable, but in no event later than ten Banking Days after each Repayment
Date, calculate and deliver to Agent the Four-Quarter Average Debt Service
Coverage Ratio and the Projected Four-Quarter Average Debt Service Coverage
Ratio. Agent shall notify Borrower in writing of any suggested corrections,
changes or adjustments which should be made to such Debt Service Coverage Ratio
calculations within 20 days after receipt. Borrower shall incorporate all such
corrections, changes or adjustment as Agent reasonably deems appropriate. The
calculations of Debt Service Coverage Ratios hereunder shall be used in
determining the application and distribution of funds from the Accounts
pursuant to Section 7.2.1 and Section 7.2.5, the distribution of funds to
Borrower pursuant to Section 6.6 and the applicable interest rate for Term
Loans under Section 2.1.2(c).
5.11 Indemnification.
5.11.1 Indemnify, defend and hold harmless Agent and
each Bank, and in their capacities as such, their respective officers,
directors, shareholders, controlling persons, employees, agents and servants
(collectively, the "Indemnitees") from and against and reimburse the
Indemnitees for:
(a) any and all claims, obligations,
liabilities, losses, damages, injuries (to person, property, or natural
resources), penalties, stamp or other similar taxes, actions, suits, judgments,
costs and expenses (including reasonable attorney's fees) of whatever kind or
nature, whether or not well founded, meritorious or unmeritorious, demanded,
asserted or claimed against any such Indemnitee (collectively, "Subject
Claims") in any way relating to, or arising out of or in connection with this
Agreement, the other Operative Documents, or the Project, except for claims by
Borrower against an Indemnitee;
(b) any and all Subject Claims arising
in connection with the release or presence of any Hazardous Substances at the
Project, whether foreseeable or unforeseeable, including all costs of removal
and disposal of such Hazardous Substances, all reasonable costs required to be
incurred in (i) determining whether the Project is in compliance and (ii)
causing the Project to be in compliance, with all applicable Legal
Requirements, all reasonable costs associated with claims for damages to
persons or property, and reasonable attorneys' and consultants' fees and court
costs; and
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(c) any and all Subject Claims in any
way relating to, or arising out of or in connection with any claims, suits,
liabilities against Borrower, any Partner or any of their Affiliates.
5.11.2 The foregoing indemnities shall not apply
with respect to an Indemnitee, to the extent arising as a result of the gross
negligence or willful misconduct of such Indemnitee, but shall continue to
apply to other Indemnitees.
5.11.3 The provisions of this Section 5.11 shall
survive foreclosure of the Collateral Documents and satisfaction or discharge
of Borrower's obligations hereunder, and shall be in addition to any other
rights and remedies of the Banks.
5.11.4 In case any action, suit or proceeding shall
be brought against any Indemnitee, such Indemnitee shall notify Borrower of the
commencement thereof, and Borrower shall be entitled, at its expense, acting
through counsel reasonably acceptable to such Indemnitee, to participate in,
and, to the extent that Borrower desires, to assume and control the defense
thereof. Such Indemnitee shall be entitled, at its expense, to participate in
any action, suit or proceeding the defense of which has been assumed by
Borrower. Notwithstanding the foregoing, Borrower shall not be entitled to
assume and control the defenses of any such action, suit or proceedings if and
to the extent that, in the reasonable opinion of such Indemnitee and its
counsel, such action, suit or proceeding involves the potential imposition of
criminal liability upon such Indemnitee or a conflict of interest between such
Indemnitee and Borrower or between such Indemnitee and another Indemnitee
(unless such conflict of interest is waived in writing by the affected
Indemnitees), and in such event (other than with respect to disputes between
such Indemnitee and another Indemnitee) Borrower shall pay the reasonable
expenses of such Indemnitee in such defense.
5.11.5 Borrower shall report to such Indemnitee on
the status of such action, suit or proceeding as material developments shall
occur and from time to time as requested by such Indemnitee (but not more
frequently than every sixty (60) days). Borrower shall deliver to such
Indemnitee a copy of each document filed or served on any party in such action,
suit or proceeding, and each material document which Borrower possesses
relating to such action, suit or proceeding.
5.11.6 (a) Notwithstanding Borrower's rights
hereunder to control certain actions, suits or proceedings, if any Indemnitee
reasonably determines that failure to compromise or settle any Subject Claim
made against such Indemnitee is reasonably likely to have an imminent and
Material Adverse Effect on such Indemnitee, such Indemnitee shall be entitled
to compromise or settle such Subject Claim.
(b) Notwithstanding Borrower's rights
hereunder to control certain actions, suits or proceedings, if the Required
Banks reasonably determine that failure to compromise or settle any Subject
Claim made against such Indemnitee is reasonably likely to have an imminent and
Material Adverse Effect on Borrower or the Project, such Indemnitee or the
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Required Banks, as the case may be, shall provide Borrower with written notice
of a proposed compromise or settlement of such claim specifying in detail the
nature and amount of such proposed settlement or compromise. Borrower shall be
deemed to have approved such proposed compromise or settlement unless, within
thirty (30) days after the date Borrower receives such notice of intended
compromise or settlement, Borrower provides such Indemnitee or the Required
Banks, as the case may be, with (i) a written legal analysis from counsel
reasonably acceptable to such Indemnitee or Required Banks, as the case may be,
reasonably concluding that, based on the magnitude of the Subject Claim, the
legal basis for such Subject Claim, and/or the cost of defending such Subject
Claim, the amount of such proposed settlement or compromise is not within a
reasonable range of settlements or compromises for such Subject Claim, and
indicating, based on such factors, such counsel's view as to the appropriate
amount of a reasonable settlement or compromise for such Subject Claim (the
"Settlement Amount"). If the Indemnitee or the Required Banks, as the case may
be, receives such legal analysis required by this Section within such thirty
(30)-day period, the Indemnitee or the Required Banks, as the case may be, may
elect to settle or compromise such Subject Claim and Borrower shall be
responsible for the payment of all amounts of such compromise or settlement up
to one hundred twenty-five percent (125%) of the Settlement Amount, such
Indemnitee shall be responsible for payment of all amounts of such compromise
or settlement in excess of such one hundred twenty-five percent (125%) limit
and such compromise or settlement shall be binding upon Borrower. If Borrower
does not provide such legal analysis within such period, or if such legal
analysis is not reasonable, in the reasonable determination of such Indemnitee
or the Required Banks, as the case may be, such Indemnitee may settle or
compromise such Subject Claim and shall be fully indemnified by Borrower
therefor. Such Indemnitee or the Required Banks, as the case may be, shall not
otherwise settle or compromise any such Subject Claim other than at its own
expense.
5.11.7 Upon payment of any Subject Claim by Borrower
pursuant to this Section 5.11 or other similar indemnity provisions contained
herein to or on behalf of an Indemnitee, Borrower, without any further action,
shall be subrogated to any and all claims that such Indemnitee may have
relating thereto, and such Indemnitee shall cooperate with Borrower and give
such further assurances as are necessary or advisable to enable Borrower
vigorously to pursue such claims.
5.11.8 Any amounts payable by Borrower pursuant to
this Section 5.11 shall be regularly payable within 30 days after Borrower
receives an invoice for such amounts from any applicable Indemnitee, and if not
paid within such 30-day period shall bear interest at the Default Rate.
5.11.9 Notwithstanding anything to the contrary set
forth herein, the Borrower shall not, in connection with any one legal
proceeding or claim, or separate but related proceedings or claims arising out
of the same general allegations or circumstances, in which the interests of the
Indemnitees do not materially differ, be liable to the Indemnitees (or any of
them) under any of the provisions set forth in this Section 5.11 for the fees
and expenses of more than one separate firm of attorneys (which firm shall be
selected by the affected Indemnitees, or upon failure to so select, by the
Agent).
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5.12 Qualifying Facility. Take or cause to be taken all
necessary or appropriate actions (a) so that the Project will be a Qualifying
Facility upon the Completion Date and at all times thereafter until all
Obligations due the Banks under the Credit Documents have been paid in full
unless the Project's failure to be a Qualifying Facility could not reasonably
be expected to have a Material Adverse Effect, and (b) to maintain Borrower's
and the Project's exemptions from regulation under the FPA (unless failure to
so maintain such exemptions could not reasonably be expected to have a Material
Adverse Effect) and PUHCA (except regulations specifically applicable to a
Qualifying Facility) or, if Calpine or its successor becomes a registered
holding company under PUHCA, as a subsidiary of such registered holding
company.
5.13 Construction of Project. Cause the Project to be
constructed and equipped substantially in accordance with the Plans and
Specifications, the Construction Contracts, the other Project Documents, the
Project Budget and the Project Schedule as the same may be amended from time to
time pursuant to Section 6.13.
5.14 Completion. Achieve Completion and Final Completion
in a timely and diligent manner in accordance with the Project Schedule, the
Project Budget, the Construction Contracts and the Plans and Specifications as
the same may be extended and, in the case of Completion, in no event later than
the Construction Loan Maturity Date.
5.15 Operation of Project and Annual Operating Budget.
5.15.1 (a) Keep the Project, or cause the same to be
kept, in good operating condition consistent with Prudent Utility Practices,
all Applicable Permits (and, if applicable, Applicable Third Party Permits),
Legal Requirements and the Operative Documents, and make or cause to be made
all repairs (structural and non-structural, extraordinary or ordinary)
necessary to keep the Project in such condition; and (b) operate the Project,
or cause the same to be operated, in a manner consistent with Prudent Utility
Practices and in compliance with the terms of the Power Purchase Documents so
as to assure, to the extent reasonably possible, the maximum generation of net
revenue for the Project consistent with the Power Purchase Documents.
5.15.2 On or before ninety (90) days prior to the
earlier of the anticipated date of Term-Conversion and the Construction Loan
Maturity Date, adopt an operating plan and a budget, detailed by month, of
anticipated revenues, anticipated expenditures under all Waterfall Levels set
forth in Section 7.2.1, and anticipated expenditures from the Major Maintenance
Reserve Account, such budget to include debt service, proposed partnership
distributions, maintenance, repair and operation expenses (including reasonable
allowance for contingencies), Major Maintenance, reserves and all other
anticipated O&M Costs for the Project for the period from the anticipated
Commercial Operation Date to the conclusion of the first full fiscal year
thereafter and, in the case of Major Maintenance in accordance with Section
5.15.3, to the conclusion of the second full fiscal year thereafter ("Annual
Operating Budget"). Such Annual Operating Budget shall be subject to the
reasonable approval of Agent and the Independent Engineer. No less than ninety
(90) days in advance of the beginning of each fiscal year thereafter, Borrower
will similarly adopt a draft Annual Operating Budget for the ensuing fiscal
year. Copies
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of the draft Annual Operating Budget shall be promptly furnished to Agent for
its review and reasonable approval. Failure by Agent to approve or disapprove
such draft Annual Operating Budget within ninety (90) days after receipt
thereof shall be deemed to be an approval by Agent of such draft. Borrower
shall incorporate Agent's suggestions into a final Annual Operating Budget,
which, subject to the provisions of the last sentence of this Section 5.15.2,
shall be prepared no less than forty-five (45) days in advance of each fiscal
year. The O&M Costs in each such Annual Operating Budget which are subject to
escalation limitations in the Project Documents shall not, absent extraordinary
circumstances, be increased by more than the amounts provided in such Project
Documents. Borrower shall continue to operate and maintain the Project, or
cause the Project to be operated and maintained, within amounts not to exceed
(a) with respect to any Major Budget Category, 105% (on a year-to-date basis)
of the amounts budgeted therefor and (b) with respect to any Budget Category,
110% (on a year-to-date basis) of the amounts budgeted therefor, each as set
forth in the then current Annual Operating Budget as approved by Agent and the
Independent Engineer; provided, however, that so long as Borrower is in
compliance with Section 6.25.1(b), the costs for fuel shall not be limited by
the Annual Operating Budget (but shall be paid in accordance with Section 7.2).
Pending approval of any Annual Operating Budget in accordance with the terms of
this Section 5.15.2, Borrower shall continue to operate and maintain the
Project, or cause the Project to be operated and maintained, within the Annual
Operating Budget then in effect; provided that the amounts specified therein
shall be increased by the amounts specified in the Project Documents.
5.15.3 Borrower shall include in each Annual
Operating Budget a re-assessment of (a) the anticipated scheduling and probable
cost of each item of Major Maintenance and (b) the anticipated amounts which
will be on deposit in the Major Maintenance Reserve Account during the
applicable fiscal year and the following fiscal year in accordance with the
then-applicable Major Maintenance Reserve Requirement. From time to time, to
the extent that Agent, in consultation with Borrower and the Independent
Engineer, reasonably determines that the anticipated cost of Major Maintenance
during the ensuing two fiscal years of Borrower is higher than that reflected
in the approved Annual Operating Budget, the amounts specified in the Annual
Operating Budget with respect to Major Maintenance may be modified by Agent.
The Major Maintenance Reserve Requirement shall be modified accordingly.
5.15.4 Replace the Operator if such Operator is not
operating the Project in accordance with the provisions hereof or the O&M
Agreement, the Power Purchase Documents, the Lease or any other agreement or
instrument under which Borrower holds title, an easement or a leasehold to the
Site, the Easements or the Collateral, and such failure could reasonably be
expected to have a Material Adverse Effect, upon receipt of notice from Agent
(after consultation with the Borrower) to the effect that, in the opinion of
the Required Banks and the Independent Engineer, said Operator has failed to
perform any material obligations set forth above; provided, however, that the
Operator may have 30 days from Borrower's receipt of notice to cure said
failure (or to establish to the satisfaction of the Required Banks that a
failure does not exist); provided, further, that if such failure cannot be
corrected within such 30 days, the Required Banks will not unreasonably
withhold their consent to an extension of such time if corrective
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action is promptly instituted by such Operator within the 30-day period and
thereafter diligently pursued until the failure is corrected and such extension
shall not have a Material Adverse Effect.
5.16 Adjustments to Project Projections. Each year at the
time Borrower prepares the Annual Operating Budget, at any time that the Annual
Operating Budget is amended, not earlier than ninety (90) days but not later
than forty-five (45) days prior to the Extension Determination Date, and also
from time to time following an event or circumstance which will materially
affect the Base Case Project Projections or the Adjusted Base Case Project
Projections, at the reasonable request of Agent, revise the Base Case Project
Projections or Adjusted Base Case Project Projections, as the case may be,
including the assumptions thereto, if appropriate, to show Borrower's
reasonable good faith estimates as of the date of preparation, for each year
through the full remaining term of the initial Base Case Project Projections,
of anticipated Project Revenues, Project Operating Revenues, O&M Costs
(including projected dates of performance of Major Maintenance), Debt Service
Coverage Ratios (on an annual basis) payments of principal, interest, fees and
other amounts payable under the Credit Documents, payments to fund required
reserves, subordinated payments and other appropriate sources and uses of
funds, as well as other data and assumptions which Borrower reasonably
considers appropriate ("Adjusted Base Case Project Projections"). The Adjusted
Base Case Project Projections shall be subject to the same approval procedures
as the Annual Operating Budget, as described in Section 5.15.2; provided,
however, that notwithstanding the foregoing, in connection with determining
whether the Extension Requirements have been satisfied, if:
(a) Borrower's proposed Adjusted Base Case
Project Projections satisfy clause (c) of the Extension Requirements;
and
(b) Agent's proposed Adjusted Base Case Project
Projections do not satisfy clause (c) of the Extension Requirements;
and
(c) Borrower's proposed Adjusted Base Case
Project Projections project an average of the annual (based on a
calendar year) Debt Service Coverage Ratios for each calendar year
through the fifteenth (15th) anniversary of Term- Conversion that
exceeds Agent's proposed Adjusted Base Case Project Projections'
forecast of such average of such annual Debt Service Coverage Ratios
by more than .25 for each calendar year through the fifteenth (15th)
anniversary of Term- Conversion; and
(d) either (i) Borrower's annual Debt Service
Coverage Ratio for each calendar year that ended since the immediately
preceding Extension Determination Date (or, in the case of the first
Extension Determination Date, since the date of Term-Conversion) has
equaled or exceeded ninety percent (90%) of the corresponding annual
(based on a calendar year) Debt Service Coverage Ratios set forth in
the Base Case Project Projections as in effect on the Closing Date or
(ii)(A) Borrower's annual Debt Service Coverage Ratio for each
calendar year but one that ended since the immediately preceding
Extension Determination Date (or, in the case of the first Extension
Determination Date, since the date of Term- Conversion) has equaled or
exceeded ninety percent (90%) of the
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corresponding annual (based on a calendar year) Debt Service Coverage
Ratios set forth in the Base Case Project Projections as in effect on
the Closing Date and (B) the average of Borrower's Debt Service
Coverage Ratios for each of the calendar years that ended since the
immediately preceding Extension Determination Date (or, in the case of
the first Extension Determination Date, since the date of
Term-Conversion) equal or exceeds the average of the Debt Service
Coverage Ratios for such calendar years set forth in the Base Case
Project Projections as in effect on the Closing Date;
then, the Base Case Project Projections or Adjusted Base Case Project
Projections shall be determined using the following procedure:
(A) Negotiation. The parties will attempt in good faith
to mutually agree on the Adjusted Base Case Project Projections by
negotiations. In order to implement such negotiations, each party shall be
entitled to give the other party written notice of such dispute (a "Dispute
Notice"). Within twenty (20) days after receipt of the Dispute Notice, the
receiving party shall submit to the other a written response. Each of the
Dispute Notice and response shall include (i) a statement of the position of
the party providing such notice or response and a summary of the evidence and
arguments supporting its position, and (ii) the name and title of the
representative of such party. The representatives shall meet at a mutually
acceptable time and place within fifteen (15) days after the date of the
response of the receiving party to the Dispute Notice and thereafter as often
as they reasonably deem necessary to exchange relevant information and to
attempt to agree upon the Adjusted Base Case Project Projections.
(B) Arbitration. In the event that the parties are
unable to agree upon the Adjusted Base Case Project Projections using the
negotiation procedures set forth in clause (A) above within thirty (30) days
after delivery of a Dispute Notice, then each of the parties shall be entitled
to have the dispute settled by arbitration using the procedures set forth in
Exhibit M.
5.17 Preservation of Rights; Further Assurances.
5.17.1 Preserve, protect and defend the rights of
Borrower under each and every Project Document, including prosecution of suits
to enforce any right of Borrower thereunder and enforcement of any claims with
respect thereto; provided, however, that upon the occurrence and during the
continuance of an Event of Default if Agent requests that certain actions be
taken and Borrower fails to take the requested actions within five Banking Days
and such failure reasonably could be expected to have a Material Adverse
Effect, Agent may enforce in its own name or in Borrower's name, such rights of
Borrower.
5.17.2 From time to time, execute, acknowledge,
record, register, deliver and/or file all such notices, statements, instruments
and other documents (including any memorandum of lease or other agreement,
financing statement, continuation statement, certificate of title or estoppel
certificate), relating to the Loans stating the interest and charges then due
and any known defaults, and take such other steps as may be necessary or
advisable to render fully valid and enforceable under all applicable laws the
rights, liens and priorities of the Banks with
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respect to all Collateral and other security from time to time furnished under
this Agreement and the other Credit Documents or intended to be so furnished,
in each case in such form and at such times as shall be satisfactory to Agent,
and pay all fees and expenses (including reasonable attorneys' fees) incident
to compliance with this Section 5.17.2.
5.17.3 If Borrower shall at any time acquire any
real property or leasehold or other interest in real property not covered by
the Deed of Trust, promptly upon such acquisition (or on the Closing Date if
such acquisition occurred prior thereto) execute, deliver and record a
supplement to the Deed of Trust, satisfactory in form and substance to Agent,
subjecting the real property or leasehold or other interests to the lien and
security interest created by the Deed of Trust. If requested by Agent,
Borrower shall obtain an appropriate endorsement or supplement to the Title
Policy insuring the Lien of the Banks in such additional property, subject only
to Permitted Liens and other exceptions to title approved by the Agent.
5.17.4 Perform, upon the request of Agent, such
reasonable acts as may be necessary to carry out the intent of this Agreement
and the other Credit Documents.
5.18 Project Equity.
5.18.1 On the Closing Date, deliver or cause to be
delivered to the Depositary Agent cash equal to $53,112,500 (the "Base
Equity"). The Depositary Agent shall deposit the Base Equity into the Equity
Account at the Depositary Agent's New York office pursuant to the Depositary
Agreement. From time to time following the Closing Date, Borrower shall have
the right to request that Agent cause the Depositary Agent to transfer amounts
from the Equity Account to the Construction Account to pay Project Costs then
due as described in a Drawdown Certificate, dated the date of the proposed
transfer and signed by Borrower. Upon the satisfaction of the conditions set
forth in Sections 3.2 (other than Section 3.2.6) and 3.4, Agent shall cause the
Depositary Agent to so transfer such amounts and such amounts shall be applied
in accordance with Section 7.1.
5.18.2 At such time, if ever, as there remain no
Available Construction Funds other than Additional Borrower Equity and there
remain Project Costs to be incurred or paid to achieve Final Completion, then
Borrower shall deposit or cause to be deposited with Agent, in cash, equity
funds in an amount equal to all such further Project Costs, such deposit to be
made on or before the date such Project Costs are due to be paid ("Additional
Borrower Equity"). All such Additional Borrower Equity proceeds shall be
deposited in the Construction Account established pursuant to Section 7.1
hereof and applied, after satisfaction of the conditions set forth in Section
3.2, to pay Project Costs.
5.18.3 Unless an Event of Default has occurred and is
continuing, have the right at any time prior to Term-Conversion to replace cash
in the Equity Account with Subordinated Debt in amount up to fifty percent
(50%) of the total Base Equity, or, provided Borrower delivers an Equity
Commitment Guaranty, with an Equity Support Letter of Credit in an amount up to
one hundred percent (100%) of the Base Equity.
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5.18.4 If Borrower elects to replace such cash with
Subordinated Debt, such Subordinated Debt shall be applied as follows: (a)
first, to Borrower in an amount equal to the lesser of the amount of such
Subordinated Debt and the amount of Base Equity previously applied to pay
Project Costs and (b) second, for deposit into the Equity Account, any
remaining Subordinated Debt to replace cash therein, in which case an amount in
the Equity Account equal to the principal amount of Subordinated Debt deposited
into the Equity Account shall promptly be delivered by the Depositary Agent to
Borrower.
5.18.5 If Borrower elects to replace such cash with
an Equity Support Letter of Credit, upon Agent's receipt of the Equity Support
Letter of Credit, receipt of the Equity Commitment Guaranty and receipt of an
executed Notice of Construction Loan Borrowing delivered in accordance with
Section 2.1.1, the Banks shall make a Construction Loan in accordance with
Section 2.1.5 in an amount equal to the lesser of (x) the Project Costs
previously paid with cash representing Base Equity, and (y) the stated amount
of the Equity Support Letter of Credit. The proceeds of such Construction Loan
shall be paid to Borrower. If the stated amount of the Equity Support Letter
of Credit is greater than the amount of the Project Costs previously paid with
such cash, on such date of receipt, Agent also shall instruct the Depositary
Agent to promptly withdraw an amount from the Equity Account equal to the
excess of such stated amount over such amount of Project Costs previously paid
and deliver such excess to Borrower.
5.18.6 In the event Borrower replaces Base Equity
with an Equity Support Letter of Credit, pay Agent when due any interest
accruing on Construction Loans that is not reflected in the Project Budget
delivered to Agent on the Closing Date and that has accrued as a result of such
replacement.
5.18.7 If an Event of Default shall have occurred
prior to Term-Conversion, transfer all remaining amounts in the Equity Account
to the Construction Account and promptly pay to Agent an amount equal to the
undrawn stated amount of any Equity Support Letter of Credit. If Borrower
fails to so pay or cause to be paid such amount, Agent shall have the right to
make a draw upon the Equity Support Letter of Credit in an amount equal to such
undrawn amount. Agent shall deposit the funds so received from or on behalf of
Borrower into the Construction Account for application in accordance with
Section 7.1.
5.18.8 Immediately prior to Term-Conversion, Borrower
and Agent will take the following actions. First, Agent shall calculate,
applying the respective formulas set forth in the Construction Contracts, the
total amount of "performance" liquidated damages that would be payable under
such Construction Contracts if such contracts had no individual limitations on
liability for such performance liquidated damages obligations (the "Maximum
TheoreticalDamages"). Next, Agent shall calculate the difference between (x)
the lesser of (A) the Maximum Theoretical Damages and (B) $20,000,000 and (y)
the aggregate amount of "performance" liquidated damages and "excess delay"
liquidated damages under the Construction Contracts applied pursuant to
Section 7.13.1 and 7.1.4, respectively, to prepay Construction Loans (the
"Actual Paid Performance Damages").
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5.18.9 If the Actual Paid Performance Damages equals
or exceeds the lesser of (A) the Maximum Theoretical Damages and (B)
$20,000,000, then Borrower shall have no further obligation regarding the
payment of Project Costs and Agent shall perform the calculation set forth in
Section 5.18.11.
5.18.10 If the Actual Paid Performance Damages is
less than the lesser of (A) the Maximum Theoretical Damages and (B)
$20,000,000, then, if the Final Project Cost is less than the Budgeted Project
Cost, Agent shall adjust the Final Project Cost by increasing the Final Project
Cost by the difference between (i) the lesser of (A) the Maximum Theoretical
Damages and (B) $20,000,000 and (ii) the Actual Paid Performance Damages.
Agent shall then use the lesser of (x) such adjusted Final Project Cost and (y)
the Budgeted Project Cost in making the calculations set forth in Section
5.18.11. If the Actual Paid Performance Damages are less than the lesser of
(A) the Maximum Theoretical Damages and (B) $20,000,000 and if the Final
Project Cost, as adjusted pursuant to this Section 5.18.10 is equal to or
greater than the Budgeted Project Cost, then Borrower shall pay or cause to be
paid to Agent an amount equal to the difference between (i) the lesser of (A)
the Maximum Theoretical Damages and (B) $20,000,000 and (ii) the Actual Paid
Performance Damages and such amount shall be applied by Agent to the prepayment
of Construction Loans.
5.18.11 Next, Agent shall compare (i) the sum of cash
as Base Equity, Subordinated Debt and draws under any Equity Support Letter of
Credit previously applied to pay Project Costs to (ii) thirty-five percent
(35%) of the Final Project Cost, as adjusted if necessary pursuant to Section
5.18.10. In the event that such sum exceeds thirty-five percent (35%) of the
adjusted Final Project Cost (the difference between such amounts, the "Excess
Equity Amount"), Borrower shall have the right to request a Construction Loan
in accordance with Section 2.1.1, and the Banks shall make a Construction Loan
to Borrower in accordance with Section 2.1.5, in an amount equal to the Excess
Equity Amount. In the event such sum is less than thirty-five percent (35%) of
the adjusted Final Project Cost (the difference between such amounts, the
"Shortfall Amount"), Borrower shall pay or cause to be paid to Agent, in
immediately available funds, an amount equal to the Shortfall Amount. If
Borrower fails to so pay or cause to be paid the Shortfall Amount, Agent shall
have the right to withdraw from the Equity Account and/or make a draw upon the
Equity Support Letter of Credit in an aggregate amount equal to the Shortfall
Amount. Agent shall deposit the funds so received from or on behalf of
Borrower into the Construction Account for application in accordance with
Section 7.1.
5.18.12 Upon Term-Conversion, pay or cause to be paid
to any holders of any Subordinated Debt, in immediately available funds, such
amounts as are necessary so that the amount of Subordinated Debt outstanding
immediately after Term-Conversion does not exceed seventeen and one-half
percent (17 1/2%) of the Final Project Cost.
5.18.13 Notwithstanding anything to the contrary in
this Agreement, in no event shall the outstanding Term Loans at Term-Conversion
exceed sixty-five (65%) of the lesser of the Final Project Cost and the
Budgeted Project Cost.
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5.19 Maintenance of Insurance. Borrower shall, without
cost to the Banks, maintain or cause to be maintained on its behalf in effect
at all times the types of insurance required pursuant to Exhibit K, in the
amounts and on the terms and conditions specified therein, with insurance
companies rated "A-" or better, with a minimum size rating of "VIII," by Best's
Insurance Guide and Key Ratings, (or an equivalent rating by another nationally
recognized insurance rating agency of similar standing if Best's Insurance
Guide and Key Ratings shall no longer be published) or other insurance
companies of recognized responsibility satisfactory to Agent.
5.20 Taxes, Other Government Charges and Utility Charges.
Pay, or cause to be paid, as and when due and prior to delinquency, all taxes,
assessments and governmental charges of any kind that may at any time be
lawfully assessed or levied against or with respect to Borrower or the Project,
including sales and use taxes and real estate taxes, all utility and other
charges incurred in the operation, maintenance, use, occupancy and upkeep of
the Project, and all assessments and charges lawfully made by any Governmental
Authority for public improvements that may be secured by a lien on the Project.
In furtherance of the foregoing, Borrower shall engage a qualified Person or
Persons to confirm Borrower's compliance with all tax laws and regulations and
to implement any required programs and procedures to ensure continued
compliance with the same. Borrower may contest in good faith any such taxes,
assessments and other charges and, in such event, may permit the taxes,
assessments or other charges so contested to remain unpaid during any period,
including appeals, when Borrower is in good faith contesting the same, so long
as (a) reserves reasonably satisfactory to Agent have been established in an
amount sufficient to pay any such taxes, assessments or other charges, accrued
interest thereon and potential penalties or other costs relating thereto, or
other adequate provision for the payment thereof shall have been made, (b)
enforcement of the contested tax, assessment or other charge is effectively
stayed for the entire duration of such contest, and (c) any tax, assessment or
other charge determined to be due, together with any interest or penalties
thereon, is immediately paid after resolution of such contest.
5.21 Event of Eminent Domain. If an Event of Eminent
Domain shall occur with respect to any Collateral, (a) promptly upon discovery
or receipt of notice of any such occurrence, provide written notice of either
to Agent, (b) diligently pursue all its rights to compensation against the
relevant Governmental Authority in respect of such Event of Eminent Domain, (c)
not, without the written consent of Agent and the Majority Banks, which consent
shall not be unreasonably withheld, compromise or settle any claim against such
Governmental Authority, (d) pay or apply all Eminent Domain Proceeds in
accordance with Section 7.10. Borrower consents to the participation of Agent
in any eminent domain proceedings, and Borrower shall from time to time deliver
to Agent all documents and instruments requested by it to permit such
participation.
5.22 Interest Rate Protection.
5.22.1 Interest Rate Agreements. On or prior to the
sixtieth (60th) day following the Closing Date, enter into with Agent (or an
Affiliate thereof) one or more Hedge
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Transactions, with an aggregate notional amount equal to Seventy-Five Million
Dollars ($75,000,000) as more particularly described in and in accordance with
the methodology set forth in that certain letter agreement, dated of even date
herewith, between Agent and Borrower.
5.22.2 Hedge Breaking Fees. To the extent required
pursuant to the terms of the Hedge Transactions, pay all reasonable costs, fees
and expenses incurred by the Borrower in connection with any unwinding, breach
or termination of such Hedge Transactions ("Hedge Breaking Fees"), all as
calculated pursuant to the applicable Interest Rate Agreements.
5.22.3 Security. Each Interest Rate Agreement
provided by Agent (or an Affiliate thereof) hereunder, including all Hedge
Transactions thereunder entered into in accordance with the terms of this
Agreement and all Hedge Breaking Fees shall be and are hereby secured by the
Collateral Documents, pari passu with the Loans. No Interest Rate Agreement
(and Hedge Transactions thereunder) not provided by Agent (or an Affiliate
thereof) hereunder may be secured by the Collateral Documents. The parties
hereto agree that, for purposes of any sharing of Collateral under the
Collateral Documents, Agent or any Affiliate thereof, in its capacity as a
counterparty or intermediary to the Interest Rate Agreements shall be deemed to
have made a Loan to Borrower in an amount equal to the unpaid amount of any
Hedge Breaking Fees owed by Borrower to Agent or such Affiliate, under any such
Hedge Transaction on the date that a "Early Termination Date" (as defined in
the applicable Interest Rate Agreement) occurs. For purposes of any such
Collateral sharing, and for purposes of voting on matters under this Agreement
to the extent specified in the definition of "Proportionate Share," Agent or
any of such Affiliates shall be deemed a Bank under the Collateral Documents to
the extent of such Loan.
5.22.4 Bank Participation. At the election of
Agent, the Banks may participate in the Interest Rate Agreements and Hedge
Transactions thereunder in proportion to their respective Proportionate Shares
by means of a risk sharing agreement in form and substance satisfactory to such
Banks, provided, that if any such Bank's Lending office is in the State of New
York, such Bank may designate another branch to enter into such risk sharing
agreement.
5.23 Alternative Thermal Host Action Plan. Upon receipt
by Borrower of an HCC Shutdown Notice, promptly deliver to Agent, for Agent's
review and approval, a proposed plan of action (as approved pursuant to this
Section 5.23, the "Alternative Thermal Host Action Plan") to procure a new
steam host. The Alternative Thermal Host Action Plan shall set forth in
reasonable detail the various alternatives considered by Borrower, the
anticipated cost to implement each such alternative and the time frame within
which each such alternative reasonably can be completed. Agent shall have
thirty (30) days following receipt of such proposed plan to approve or
disapprove the proposed plan. Failure to disapprove such plan within such
thirty (30)-day period shall be deemed as Agent's approval of such plan. If
Agent disapproves such plan, Borrower and Agent shall promptly meet and
negotiate in good faith to achieve a mutually acceptable plan. Upon such
agreement, Borrower shall promptly implement the Alternative Thermal Host
Action Plan.
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5.24 Performance Bonds. Cause Westinghouse and Prime
Contractor to deliver the bonds required under the respective Construction
Contracts within forty-five (45) days after the Closing Date.
5.25 Power Marketing.
5.25.1 Replacement of Power Marketer. If any of the
following events shall occur:
(a) an Event of Default under Section
8.1.7(b) of this Agreement as a result of a breach or default by Power
Marketer under a Project Document or Consent,
(b) a breach, default or failure to
perform by Power Marketer under any provision in any contract or
agreement between Power Marketer and any other Person (other than
Borrower) if such breach, default or failure to perform (i) materially
interferes with or impairs Borrower's ability to sell energy and/or
capacity generated by the Project and collect its revenues from such
sales and (ii) is not cured within the time periods provided in such
contracts or agreements (not to exceed ninety (90) days), or
(c) the Project's Four-Quarter Average
Debt Service Coverage Ratio calculated at the end of any four (4)
consecutive calendar quarters is less than 2.00 to 1.00,
then, if requested by Agent after consultation with Borrower and consideration
of the facts and circumstances affecting the Project's performance and results,
terminate all contracts and agreements with the then Power Marketer, including
all Power Marketing Services Agreements, Power Marketing Brokering Agreements
and ERCOT Power Purchase Agreements with the Power Marketer, and replace the
Power Marketer with another Power Marketer that is satisfactory to Agent;
provided, however, that any such termination shall be prospective only and
shall not affect Borrower's obligations to supply energy and/or capacity with
respect to transactions entered into or obligations incurred prior to the
effective date of such termination.
5.25.2 Requests for Proposals. From and after the
Closing and until the earlier to occur of (a) the fourth anniversary of
Term-Conversion and (b) Borrower having entered into Bidding Threshold Power
Sales Agreements covering, in the aggregate, at least 75 MW of "firm" energy
and/or capacity, unless Agent otherwise consents, which consent shall not be
unreasonably withheld, submit or cause Power Marketer to submit on its behalf,
bona fide, good faith bids on all requests for proposal or similar offers which
can then be supplied in whole or in part from the Project to enter into Bidding
Threshold Power Sales Agreements and/or Pasadena Unit Power Sales Agreements
meeting the requirements of a Bidding Threshold Power Sales Agreement.
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5.25.3 Firm Sales to HL&P. In the event that, by
April 15 (or such later date as Agent may agree) next preceding the anticipated
Commercial Operation Date, there exists a shortfall between the aggregate
amount of firm energy and/or capacity covered by all Distribution Threshold
Power Sales Agreements entered into by Borrower and 75 MW at such time, then
Borrower shall, on or before the May 1 next preceding the anticipated
Commercial Operation Date, elect the "Firm Energy Option" under the HL&P Power
Purchase Agreement and schedule at least the amount of such shortfall for the
periods beginning on the June 1 next preceding the anticipated Commercial
Operation Date and each June 1 thereafter, unless Agent otherwise consents
(until such time as such shortfall has been eliminated or the fourth
anniversary of Term-Conversion has occurred, whichever occurs earlier) and
ending on the following May 1; provided, however, that such election may
schedule zero firm energy for the period from the June 1 immediately preceding
the anticipated Commercial Operation Date through the end of the month
following the anticipated Commercial Operation Date.
5.25.4 Arrangements with Power Marketer.
(a) Promptly after the Closing Date
enter into (i) a power marketing brokering agreement with Power Marketer in
form and substance reasonably acceptable to Agent (the "Power Marketing
Brokering Agreement"), (ii) a power marketing services agreement with Power
Marketer in form and substance reasonably acceptable to Agent (the "Power
Marketing Services Agreement", and (iii) the Power Marketing Security
Agreement.
(b) Prior to entering into any ERCOT
Power Purchase Agreements or selling any energy or capacity to or through Power
Marketer, cause Power Marketer to (i) establish a depository account (the
"Power Marketing Depository Account") with a depository agent satisfactory to
Agent and (ii) grant to Borrower a first priority perfected security interest
in such account and all funds and instruments deposited therein.
(c) In connection with the establishment
of the Power Marketing Depository Account as provided in Section 5.25.4(b)
above and at all times thereafter, cause Power Marketer to maintain a minimum
balance in the Power Marketing Depository Account equal to the Power Marketing
Minimum Balance; provided, however, that:
(A) During the ninety (90) days
immediately following the first day on which Power Marketer sells,
pursuant to a System Power Sales Agreement, energy and/or capacity
generated and/or made available by the Project, Power Marketer may, in
lieu of maintaining the Power Marketing Minimum Balance in the Power
Marketing Depository Account, cause Calpine to guarantee to Borrower
payment by Power Marketer of the shortfall, existing from time to time
during such ninety (90) day period, between the amount of funds on
deposit in the Power Marketing Depositary Account and the Power
Marketing Minimum Balance. Such guarantee shall be in substantially
the form of Exhibit D-2B.
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(B) At any time, Power Marketer
may, in lieu of maintaining the Power Marketing Minimum Balance in the
Power Marketing Depositary Account, cause a Person that satisfies the
Power Marketing Guaranty Requirements to guarantee to Borrower payment
by Power Marketer of the amounts owed to Borrower under all
Pasadena/CPSC System Supported Contracts, existing from time to time;
provided, however, that such Person's liability under such guaranty
shall be limited to an amount equal to the Power Marketing Minimum
Balance in effect while such guaranty is in effect. Such guaranty
shall be in substantially the form of Exhibit D-2B. If Agent shall,
at any time, but not more frequently than once a year, reasonably
believe that such guarantor is no longer rated at least BBB+ or the
equivalent thereof by S&P or at least Baa1 or the equivalent thereof
by Moody's, then Agent may request that such guarantor receive an
indicative rating from such rating agencies. If in connection with
such requested rating, or for any other reason, such guarantor shall
at any time cease to satisfy any of the requirements set forth in the
definition of "Power Marketing Guaranty Requirements," then Power
Marketer shall promptly, but in no event more than fifteen (15) days
after the failure of any of such requirements to be satisfied, restore
the balance in the Power Marketing Depository Account to the Power
Marketing Minimum Balance then in effect.
(d) Cause Power Marketer to instruct all
purchasers under Pasadena Unit Power Sales Agreements to make all payments due
thereunder to Power Marketer directly into the Revenue Account.
(e) Cause Power Marketer to (i) promptly
upon execution thereof, collaterally assign to Borrower all of Power Marketer's
rights and interests to all Pasadena Unit Power Sales Agreements and (ii)
obtain consents to such collateral assignments from the purchasers thereunder
as described in Section 6.25.
5.26 Auxiliary Boilers Contractor. In the event that
ABCO, as the Contractor under the Auxiliary Boilers Purchase Contract, fails to
achieve any of the milestones set forth on the "Contract Schedule" (as defined
in the Auxiliary Boilers Purchase Contract) on or prior to seventy-five (75)
days after the scheduled date for achieving such milestone, then upon request
of Agent, as promptly as practicable terminate the Auxiliary Boilers Purchase
Contract and engage a replacement contractor to supply to the Project auxiliary
boilers conforming to the Project's plan and specification.
5.27 Construction Management Plan. On or before sixty
(60) days after the Closing, adopt a draft construction plan (the "Construction
Plan") setting forth a schedule, detailed by month, of the anticipated
milestones to be accomplished in connection with the construction of the
Project and describing the interfacing procedures among the various
Contractors. The Construction Plan shall be subject to the reasonable approval
of Agent. Failure by Agent to approve or disapprove the draft Construction
Plan within thirty (30) days after receipt thereof shall be deemed to be an
approval by Agent of such draft. Borrower shall incorporate Agent's reasonable
suggestions into a final Construction Plan.
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5.28 Operating Agreements. On or before January 31, 1998,
(a) enter into with HL&P, or another entity providing "control area" services
reasonably acceptable to Agent, an agreement whereby HL&P or such other entity
will provide standby station electric service to the Project and (b) enter
into, or cause Power Marketer to enter into on behalf of Borrower, an agreement
with HL&P, or another entity providing "control area" services reasonably
acceptable to Agent, whereby HL&P or such other entity will provide ancillary
services, wheeling and transmission services to the Project, each in form and
substance satisfactory to Agent.
5.29 Stand-Alone Easements. On or before thirty (30) days
after the earliest to occur of the events specified in clauses (a), (b) and (c)
of Section 3.3.6 of the Lease, make an election under Section 3.3.6 of the
Lease to use the "Stand-Alone Easements" (as defined in the Lease) and thereby
convert them into "Operating Easements" (as defined in the Lease).
5.30 Extension of Lease, Lease of Expansion Property. In
the event that the "Initial Term" (as defined in the Lease) of the Lease is not
extended pursuant to Section 4.2 or 4.3 of the Lease, and unless Phillips
exercises the "Project Purchase Option" (as defined in the Lease), exercise its
option as provided in Section 4.4 of the Lease to extend the Initial Term for
the "Partnership Extension Term" (as defined in the Lease). If directed by
Agent, Borrower shall exercise its option to lease the Expansion Property.
5.31 License from Port Authority. As promptly as
practicable after the Closing Date, and in any event within ninety (90) days
thereafter, deliver to Agent a license executed by the Port Authority in favor
of Borrower relating to certain transmission lines for Project, and \a consent
to assignment thereto executed by the Port Authority in favor of Agent, each in
form and substance reasonably satisfactory to Agent.
5.32 Phillips License from Port Authority. As promptly as
practicable after the Closing Date, and in any event within one hundred twenty
(120) days thereafter, cause Phillips to amend that certain Oil, Gas, Etc.
Pipeline License (Railroad Right-of-Way), dated April 1, 1990, between the Port
and Phillips 66 Company, predecessor in interest to Phillips, to enable
Borrower and its Contractors to construct such improvements in the area
described in such License as are necessary for Borrower to comply with the
Lease.
5.33 Conversion. Cause the conditions set forth in
Section 3.3 (other than Section 3.3.4) to occur as promptly as practicable
after Completion has occurred.
5.34 Option Title Insurance. To the extent permitted
under Texas law, within sixty (60) days following the Closing Date, cause the
Title Insurer to reissue the Title Policy or issue an endorsement to the Title
Policy insuring the "Expansion Property" and the "QF Property" (as such terms
are defined in the Lease) (or the validity of the options with respect thereto)
to the same extent as the remainder of the Site.
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ARTICLE 6 - NEGATIVE COVENANTS
Borrower covenants and agrees that so long as this Agreement
is in effect, it will not:
6.1 Contingent Liabilities. Except as provided in this
Agreement, become liable as a surety, guarantor, accommodation endorser or
otherwise, for or upon the obligation of any other Person; provided, however,
that this Section 6.1 shall not be deemed to prohibit (a) the acquisition of
goods, supplies or merchandise in the normal course of business or normal trade
credit; (b) the endorsement of negotiable instruments received in the normal
course of its business; or (c) contingent liabilities required under any
Applicable Permit or Operative Document.
6.2 Limitations on Liens. Create, assume or suffer to
exist any Lien, securing a charge or obligation on the Project or on any of the
Collateral, real or personal, whether now owned or hereafter acquired, except
Permitted Liens.
6.3 Indebtedness. Incur, create, assume or permit to
exist any Debt except Permitted Debt.
6.4 Sale or Lease of Assets. Sell, lease, assign,
transfer or otherwise dispose of assets, whether now owned or hereafter
acquired (a) except in the ordinary course of its business as contemplated by
the Operative Documents or (b) except to the extent that such property is worn
out or no longer useful or usable in connection with the operation of the
Project, and in each case at fair market value.
6.5 Changes. Change the nature of its business or expand
its business beyond the business contemplated in the Operative Documents,
including without limitation purchasing gas with the intention of reselling
such gas.
6.6 Distributions. Directly or indirectly, make or
declare any distribution (in cash, property or obligation) on, or other payment
on account of, any interest in Borrower (including any transfers of any tax
benefits):
(a) until each of the conditions to the initial
distribution set forth in Section 3.5 has been satisfied; and
(b) unless (i) on a Calculation Date; (ii)
Term-Conversion has occurred; (iii) no Event of Default or Inchoate Default has
occurred and is continuing; (iv) the Four-Quarter Average Debt Service Coverage
Ratio calculated as of the Repayment Date to which such Calculation Date
relates is equal to or greater than 1.50 to 1.00; (v) the Projected
Four-Quarter Average Debt Service Coverage Ratio calculated as of the Repayment
Date to which such Calculation Date relates is equal to or greater than 1.50 to
1.00; (vi) such payment would not trigger an Inchoate Default or Event of
Default and (vii) such distribution is made at Waterfall Level 11 or from the
Distribution Suspense Account.
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6.7 Investments. Make any investments (whether by
purchase of stocks, bonds, notes or other securities, loan, extension of
credit, advance or otherwise) other than Permitted Investments.
6.8 Transactions With Affiliates. Except for (a) the
Equity Documents, the Project Documents and the transactions permitted thereby,
(b) arms-length transactions in the ordinary course of business not to exceed
in the aggregate $100,000 per calendar year, and (c) as otherwise expressly
permitted by this Agreement and the other Credit Documents, directly or
indirectly enter into any transaction or series of transactions with or for the
benefit of an Affiliate without the prior written approval of Agent.
6.9 Regulations. Directly or indirectly apply any part
of the proceeds of any Loan or other revenues to the purchasing or carrying of
any margin stock within the meaning of Regulations G, T, U or X of the Federal
Reserve Board, or any regulations, interpretations or rulings thereunder.
6.10 ERISA. Establish, maintain, contribute to or become
obligated to contribute to any ERISA Plan or suffer or permit any member of the
Controlled Group to do so.
6.11 Partnerships, etc. Become a general or limited
partner in any partnership or a joint venturer in any joint venture or create
and hold stock in any subsidiary.
6.12 Dissolution. Liquidate or dissolve, or sell or lease
or otherwise transfer or dispose of all or any substantial part of its
property, assets or business or combine, merge or consolidate with or into any
other entity, or change its legal form, or purchase or otherwise acquire all or
substantially all of the assets of any Person.
6.13 Amendments; Change Orders; Completion.
6.13.1 Directly or indirectly, amend, modify,
supplement or waive, or permit or consent to the amendment, modification,
supplement or waiver (including, without limitation, any waiver (or refund) of
liquidated damages payable by any Contractor under any Construction Contract)
of, any of the provisions of, or give any consent under, (a) any of the Project
Documents without first submitting to Agent a copy of such proposed amendment,
modification, supplement or waiver and if, in the reasonable judgment of the
Agent, the amendment, modification, supplement or waiver could reasonably be
expected to have a Material Adverse Effect, obtaining the prior written consent
of the Majority Banks thereto, which consent shall not be unreasonably withheld
or delayed or (b) the Energy Sales Agreement, the HL&P Power Purchase
Agreement, the Lease or the Facility Services Agreement without obtaining the
prior written consent of the Required Banks thereto or (c) the Power Marketing
Services Agreement or the Power Marketing Brokering Agreement without obtaining
the prior written consent of the Majority Banks thereto.
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6.13.2 Without the prior written consent of Agent
direct or consent to any change order under any of the Construction Contracts
if such change order:
(a) will, individually or together with
all previous change orders, increase or decrease the Project Costs by more than
$750,000 in the aggregate for the Project (exclusive of increases reimbursed by
insurance awards, condemnation awards or contractual damage awards);
(b) will materially delay Completion, or
in any event is reasonably likely to delay Completion beyond the Construction
Loan Maturity Date;
(c) is reasonably likely to permit or
result in any adverse modification or impair the enforceability of any warranty
under any Construction Contract or the O&M Agreement;
(d) is reasonably likely, in the opinion
of the Independent Engineer, to impair or reduce the maximum capacity, value,
efficiency, utility, output, performance, reliability, durability or
availability of the Project, or increase O&M Costs, or decrease Project
Revenues, in each case after accounting for other favorable or unfavorable
circumstances which may have affected the Project;
(e) is not permitted by any Project
Document or would (i) diminish any obligation of any Major Project Participant
or (ii) increase any obligation of Borrower thereunder;
(f) is likely, in the reasonable opinion
of Agent, to present a significant risk of the revocation or material
modification of any Applicable Permit or Third Party Permit or jeopardize the
Project's status as a Qualifying Facility;
(g) may cause the Project not to comply
or lessen the Project's ability to comply with Legal Requirements; or
(h) relates to a Construction Contract
between Borrower and an Affiliate of Borrower.
6.13.3 Declare "Completion," "Final Construction
Completion", "Final Project Completion" "Mechanical Completion", (as such terms
are defined in the Construction Contracts) of the Project under the
Construction Contracts or declare that the "Acceptance Date" has occurred or
approve the successful completion of the "Acceptance Tests" (as such terms are
defined in the Construction Contracts) without the written approval of Agent,
which approval, if given, shall not be unreasonably delayed, acting in
consultation with the Independent Engineer.
6.13.4 Conduct any Performance Tests under and as
defined in the Power Island Purchase Contract without the provision by Phillips
of Off-Gas (as defined in the Facility
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Services Agreement) in the quantities and qualities provided for in the
Facility Services Agreement.
6.13.5 Agree on the Punch List without the written
approval of Agent acting in consultation with the Independent Engineer.
6.13.6 Approve of the hiring by any Contractor of
any Major Subcontractor not previously approved by Agent acting in consultation
with the Independent Engineer.
6.13.7 Unless compliance hereof is waived in writing
by Agent and the Majority Banks, direct or consent to any change order under
the O&M Agreement if such aggregate.
6.13.8 Consent, without Agent's prior approval, to
(a) any action taken by any Contractor to conform the equipment or services
provided by such Contractor to the intellectual property rights of others if
such action could reasonably be expected to materially and adversely affect
Borrower's continued use of the Project or (b) to the settlement by any
Contractor of any claim or proceeding which could reasonably be expected to
adversely affect Borrower's rights.
6.13.9 Direct any Contractor to suspend the work
being performed under any Construction Contract without Agent's prior consent.
6.13.10 Agent shall use good faith efforts to
respond to each change order request as soon as possible and in all events
within 30 days. No change order shall be deemed approved by Agent until
expressly approved.
6.14 Compliance with Operative Documents. Do or permit
(to the extent within its control) to be done in, upon or about the Project or
any part thereof, or do or permit (to the extent within its control) to be done
any act under the Operative Documents, or omit or refrain from any act under
the Operative Documents, where such act done or permitted to be done, or such
omission of or refraining from action, could reasonably be expected to have a
Material Adverse Effect.
6.15 Name and Location; Fiscal Year. Unless waived in
writing by Agent, change its name, the location of its principal place of
business or its federal employer identification number without notice to Agent
at least 45 days prior to such change, or change its fiscal year without
Agent's consent.
6.16 Use of Project Site. Use, or permit to be used, the
Site for any purpose other than for the construction, operation and maintenance
of the Project as contemplated by the Operative Documents, without the prior
written approval of Agent.
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6.17 Assignment. Assign its rights hereunder or under any
of the Operative Documents to any Person except as permitted under this
Agreement and the other Credit Documents.
6.18 Abandonment of Project. Voluntarily cease or abandon
the development, construction or operation of the Project.
6.19 Hazardous Substance. Release, emit or discharge into
the environment any Hazardous Substances in violation of any Hazardous
Substance Laws, Legal Requirements or Applicable Permits.
6.20 Additional Project Documents. Enter into or become a
party to any Additional Project Document, except (a) with the prior written
consent of Agent acting at the direction of the Majority Banks, and (b) if
required by the Agent, upon delivery to the Agent of a Consent from such third
party in substantially the form of Exhibit E-1; provided that the consent of
the Agent and the Majority Banks shall not be required for Borrower to enter
into Additional Project Documents (i) with Persons other than Affiliates of
Borrower and (ii) pursuant to which Borrower will incur obligations or
liabilities with a value of not more than $100,000 individually, or $200,000 in
the aggregate, per year.
6.21 Project Budget Amendments. Directly or indirectly,
amend, modify, allocate, re-allocate or supplement or permit or consent to the
amendment, modification, allocation, re-allocation or supplement or, any of the
provisions of the Project Budget, except that Borrower may:
6.21.1 allocate up to $1,000,000 in the aggregate of
Unrestricted Owner's Contingency to any Budget Categories (other than any line
items pertaining to a transaction with an Affiliate);
6.21.2 after obtaining the prior written consent of
the Agent, allocate all or any portion of Unrestricted Owner's Contingency to
any Budget Categories (other than any line items pertaining to a transaction
with an Affiliate);
6.21.3 upon completion in full of the work or other
activity to which any particular Budget Category relates, reallocate any amount
remaining in such Budget Category to one or more other Budget Categories (other
than any line items pertaining to a transaction with an Affiliate);
6.21.4 after obtaining the prior written consent of
Agent, re-allocate to the Unrestricted Owner's Contingency amounts previously
allocated to any Budget Category pursuant to Section 6.21.1 above, to the
extent that Borrower reasonably determines that such amounts are no longer
required to be allocated to such Budget Category;
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6.21.5 after obtaining the prior written consent of
Agent and the Majority Banks, allocate all or any portion of the Restricted
Owner's Contingency to such Budget Categories as Borrower considers
appropriate; and
6.21.6 make such other allocations and
re-allocations with respect to the Project Budget which are approved in writing
by Agent and the Majority Banks prior thereto.
All allocations and re-allocations made in accordance with the terms hereof
shall be prepared and computed using the same methodology and, upon each such
allocation, re-allocation and restoration, (a) the Project Budget shall be
deemed amended to reflect such allocation, re-allocation or restoration upon
notice by Borrower to Agent of such allocation, re-allocation or restoration,
and (b) Borrower shall promptly prepare and distribute to the Agent an
appropriately revised Project Budget. Any increases to the Budget Category
entitled Interest During Construction shall be made first from Unrestricted
Owner's Contingency and, to the extent that the Unrestricted Owner's
Contingency has been utilized in full, from Restricted Owner's Contingency,
subject in all cases to the approval rights contained in this Section 6.21.
6.22 Loan Proceeds; Project Revenues. Use, pay, transfer,
distribute or dispose of any Loan proceeds in any manner or for any purposes
except as provided in Section 5.1.1 or of any Project Revenues in any manner or
for any Purposes except as provided in Sections 5.1.2 and 7.2.
6.23 Commercial Operation Date. Declare or cause to occur
the Commercial Operation Date under the Energy Sales Agreement without Agent's
prior written consent, which consent may be withheld in Agent's sole
discretion.
6.24 Suspension of Performance Under Gas Sales Agreement.
Direct Fuel Supplier to suspend performance under the Gas Sales Agreement
without Agent's prior written consent, which consent shall not be unreasonably
withheld so long as Borrower has entered into or concurrently enters into
alternative fuel supply contracts or other arrangements (i) which provide for
all of the Project's fuel requirements, (ii) which provide for subordination of
10% of the cost of fuel in substantially the same manner as provided in
Sections 7.2.1 and 7.2.3 and contain substantially the same provisions as are
set forth in Section 8 of the Gas Sales Agreement or make alternative
arrangements reasonably satisfactory to Agent which, based on the Adjusted Base
Case Project Projections, would result in projected annual Debt Service
Coverage Ratios that are equal to or greater than the projected annual Debt
Service Coverage Ratios that would be achieved with such subordination, and
(iii) are with fuel suppliers reasonably acceptable to Agent.
6.25 Power Marketing.
6.25.1 Power Sales Agreements. Without Agent's
prior written consent, enter into an ERCOT Power Purchase Agreement, or allow
Power Marketer to enter into any Power Marketer Power Sales Agreement which
uses services from the Project which:
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(a) except as otherwise permitted or
required in Sections 5.25.2 and 5.25.3 of this Agreement, is not intended to
maximize, in the long-term, the net revenues and profitability of the Project
over the Term or results in a fluctuation in net revenues per kWh under such
agreement of more than ten percent (10%) from the net revenues per kWh
generated under such agreement in either the preceding or following year.
(b) in the case of such agreements for 5
MW or more individually, or 20 MW or more in the aggregate, has a term of three
years or more and whose variable pricing component is not indexed to the price
of gas that Borrower pays under the Gas Sales Agreement;
(c) in the case of such agreements of a
term that exceeds one year, results when aggregated with existing ERCOT Power
Purchase Agreements and Power Marketer Power Sales Agreements of a term that
exceeds one year, on an annual basis over the life of such agreement, in per
kWh gross revenues to the Project that are less than the per kWh gross revenues
to the Project set forth in the Base Case Project Projections as in effect on
the Closing Date;
(d) in the case of agreements for the
sale of firm energy of a term that exceed one year, are not with parties (i)
listed in Appendix A to Borrower's Power Marketing Plan, (ii) whose credit
rating is equal to or better than BB, as rated by S&P (or an equivalent
rating), (iii) whose obligations under such agreements are guaranteed in form
and substance acceptable to Agent by a party whose credit rating is equal to or
greater than BB, as rated by S&P (or an equivalent rating) or (iv) whose
obligations under such agreements are secured by a letter of credit, in form
and substance acceptable to Agent and issued by a financial institution
reasonably acceptable to Agent or other security reasonably acceptable to
Agent.
(e) provide for payment by the purchaser
thereunder for energy or capacity more than sixty- five (65) days after the
energy or capacity was delivered or made available, as the case may be;
(f) do not (i) explicitly preclude any
liability by Borrower for consequential, special and indirect damages including
loss of revenues and (ii) if such agreement is entered into with Power
Marketer, require Power Marketer to indemnify Borrower from and against any
such potential liability sought to be imposed by third parties; or
(g) require Borrower to provide
collateral security to a third party for performance of Borrower's obligations
under such agreement; provided, however, that nothing herein shall restrict or
limit the right of any Affiliates of Borrower (other than the Partners) to
provide any such collateral security.
6.25.2 Capacity Limitations. Sell any electrical
capacity from the Project (a) pursuant to an agreement which does not permit
the buyer of such capacity to request the delivery of energy in the amount of
such capacity or (b) pursuant to any agreement unless such
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capacity is supported by an equal amount of available uncommitted energy from
the Project; provided, however, that nothing herein shall restrict Borrower's
right or ability to sell interruptible or non-firm energy regardless of the
amount of capacity sold or energy committed from the Project.
6.25.3 Power Marketing Affiliates. Permit Calpine
or any of its Affiliates, individually or together with any other Person or
Persons, to form or establish any power marketing entities (other than CPSC)
that are qualified for or otherwise participate or operate in ERCOT; provided,
however, that Calpine or CPSC may form a subsidiary to participate in ERCOT in
which case such subsidiary shall be the only Affiliate of Borrower which is
qualified for or otherwise participates or operates in ERCOT.
6.25.4 Collateral Assignment. Without Agent's
consent, enter into any ERCOT Power Purchase Agreements which do not contain an
acknowledgment and a consent to the collateral assignment of such agreements to
the Banks which acknowledgment and consent shall be in a form reasonably
acceptable to Agent.
6.26 Expansion Property. Without Agent's consent,
exercise its option to lease the Expansion Property (as defined in the Lease)
under Section 6.2 of the Lease or fail to enter into an extension or renewal of
any of the Phillips Documents.
ARTICLE 7 - APPLICATION OF FUNDS
7.1 Construction Account.
7.1.1 Establishment of Account. On or prior to the
Closing Date, Borrower and Agent shall establish the Construction Account at
the Depositary Agent's New York office. There shall be deposited into the
Construction Account the proceeds of all Construction Loans made hereunder, all
Project Operating Revenues earned prior to Term-Conversion (which shall be
available for the payment of Project Costs pursuant to the terms of this
Agreement), and all amounts required to be deposited in the Construction
Account pursuant to Section 5.18.
7.1.2 Disbursements from Construction Account.
Amounts shall be disbursed from the Construction Account from time to time
subject to the satisfaction (or waiver) of the provisions of Section 3.2 and
this Section 7.1. Borrower shall have the right to cause Agent to disburse
amounts from the Construction Account to the accounts of each of the
Contractors for amounts due and owing to such Contractors under the
Construction Contracts, or to any other materialmen, subcontractors, the Agent
or any other Person in payment of amounts due and owing to such parties from
Borrower in accordance with a duly completed Drawdown Certificate. Borrower
agrees that Agent may transfer any or all of a Construction Loan and other sums
in the Construction Account directly into the account of any Contractor for
amounts due and owing to such Contractor under the relevant Construction
Contract, or any other materialmen or subcontractors in payment of amounts due
and owing to such parties from Borrower without further authorization from
Borrower; provided, however, that if Borrower has notified Agent that
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it is contesting a claim for payment by a Contractor or a subcontractor or
materialmen in accordance with the requirements of this Agreement and the
definition of "Permitted Liens," Agent will not, except as described in the
proviso to the next sentence, be entitled to pay any amount being contested.
Borrower hereby constitutes and appoints Agent its true and lawful
attorney-in-fact to make such direct payments and this power of attorney shall
be deemed to be a power coupled with an interest and shall be irrevocable;
provided that, except upon the occurrence and continuation of an Event of
Default, Agent shall not exercise its rights under this power of attorney
except to make payments (a) as directed by Borrower or (b) which Agent
reasonably believes, if not promptly made, are reasonably likely to have a
Material Adverse Effect. No further direction or authorization from Borrower
shall be necessary to warrant or permit Agent to make such direct Construction
Loans in accordance with the foregoing sentence, and all such direct
Construction Loans shall satisfy pro tanto the obligations of Agent and the
Banks hereunder, and shall be secured by the Collateral Documents as fully as
if made directly to Borrower, regardless of the disposition thereof by any
Contractor, or any other subcontractors, materialmen, laborers or other
parties.
7.1.3 Rights of Agent. Agent will have the right,
but not the obligation, to (a) supply any missing endorsements of Borrower,
refuse any item for deposit except as required by the terms of this Agreement,
and pay and charge items payable by Agent pursuant to Section 7.1.2 in any
order convenient to Agent; (b) refuse to honor any check drawn on the
Construction Account which is not consistent with this Agreement, or which has
been improperly filled out or endorsed; (c) create and charge to the
Construction Account overdrafts and all applicable charges; (d) remit copies of
checks and other items with statements instead of the originals which may be
retained by Agent; and (e) pay fees, interest and other charges owing by
Borrower as provided herein.
7.1.4 Proceeds of the Final Drawing. Upon
Term-Conversion, after deposit of all proceeds of the Final Drawing, if any, in
the Construction Account, all amounts remaining in the Construction Account (if
any) shall be applied as follows:
(a) An amount sufficient for completion
of the Punch List, and payment of other Project Costs through Final Completion,
determined by Borrower and approved by Agent in consultation with the
Independent Engineer, shall be retained in the Construction Account for
application in accordance with Section 7.1.5; and
(b) Any amounts representing delay
damages under any Construction Contracts shall be applied to the prepayment of
Construction Loans to the extent that performance liquidated damages under any
Construction Contracts would have become payable under such Construction
Contracts but for a limitation on the amount of such liquidated damages under
the relevant Construction Contract.
(c) All other amounts in the
Construction Account shall be transferred (i) first, to the Emissions Offsets
Reserve Account until the balance therein equals the EORA Minimum Balance, (ii)
second, to the Fuel Supply Reserve Account until the balance
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therein equals the FSRA Minimum Balance, and (iii) third, to the Debt Service
Reserve Account in an amount equal to the DSRA Minimum Balance. To the extent
excess amounts remain in the Construction Account after effecting the
applications in the immediately preceding sentence, such excess funds shall be
deposited in the Revenue Account and applied in accordance with Section 7.2.1.
7.1.5 Disbursements Following Term-Conversion.
From and after Term-Conversion until Final Completion, amounts in the
Construction Account shall be disbursed from time to time (but no more
frequently than twice per month) to Borrower in accordance with this Section
7.1 after satisfaction (or waiver) of such conditions set forth in Section 3.2
as Agent in its reasonable discretion requires to be satisfied, to pay for
completion of the Punch List and other items necessary to achieve Final
Completion. Following achievement of Final Completion, amounts, if any,
remaining in the Construction Account shall be transferred to the Revenue
Account for application in accordance with the terms of Section 7.2.1.
7.2 Revenue Account.
7.2.1 Establishment of Account; Priority of
Payments. On or prior to Term-Conversion, Borrower and Agent shall establish
the Revenue Account at the Depositary Agent's New York office. There shall be
deposited into the Revenue Account all Project Operating Revenues earned on or
after Term-Conversion. So long as no Event of Default has occurred and is
continuing, or will occur upon giving effect to the application described
below, funds in the Revenue Account shall be applied at the following times and
in the following order of priority by disbursement or internal account transfer
by the Depositary Agent, (a) on Agent's volition with respect to Waterfall
Levels 1 through 8 or if Agent reasonably believes that failure to make any
such payment could reasonably be expected to have a Material Adverse Effect, or
(b) pursuant to Borrower's disbursement requisition, directly to the Person
entitled thereto, in each case at the following times, commencing on the date
of Term-Conversion, and in the following order of priority (each, a "Waterfall
Level"):
(1) on the last Banking Day of each
month, provided that the Agent has timely received and approved a Disbursement
Requisition delivered pursuant to Section 7.2.2, to the Operating Account for
payment of Senior O&M Costs in an amount determined pursuant to Section 7.2.2,
below;
(2) on the last Banking Day of each
month, to the Accrual Sub-Account as required by Section 7.9;
(3) from time to time in the priority
indicated, as and when due under the terms of this Agreement, to the payment of
all fees, costs, charges and any other amounts due and payable to Agent and the
Banks in connection with this Agreement and the other Credit Documents, other
than Commitment Fees and amounts described in another Waterfall Level;
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(4) from time to time, on a pro rata
basis among the Banks, to the payment of interest on the Term Loans, Commitment
Fees and to payments due by Borrower pursuant to the Interest Rate Agreements
(and the Hedge Transactions thereunder);
(5) on Repayment Dates, on a pro rata
basis among the Banks, to (a) the payment of principal due on the Term Loans in
accordance with Exhibit I and (b) other principal amounts due hereunder;
(6) on Repayment Dates, to the Major
Maintenance Reserve Account as required by Section 7.3;
(7) on Repayment Dates, to the Debt
Service Reserve Account as required by Section 7.6 (the balance remaining in
the Revenue Account after the application of the foregoing payments set forth
in Waterfall Levels 1 through 7 is referred to herein as the "Available Cash");
(8) on Repayment Dates or Calculation
Dates, as the case may be, and only in respect of amounts which were on deposit
in the Revenue Account on the Repayment Date to which such Calculation Date
relates, to Mandatory Prepayment of the Loans and other Obligations to the
extent required under Section 7.2.5;
(9) on Calculation Dates, and only in
respect of amounts which were on deposit in the Revenue Account on the
Repayment Date to which such Calculation Date relates, provided that Agent has
timely received and approved a Disbursement Requisition delivered pursuant to
Section 7.2.3, to the payment of Subordinated Fuel Costs in an amount
determined pursuant to Section 7.2.3 below;
(10) on Calculation Dates, and only in
respect of amounts which were on deposit in the Revenue Account on the
Repayment Date to which such Calculation Date relates, provided that Agent has
timely received and approved a Disbursement Requisition delivered pursuant to
Section 7.2.4, to the payment of Subordinated O&M Costs in an amount determined
pursuant to Section 7.2.4 below; and
(11) on Calculation Dates, and only in
respect of amounts which were on deposit in the Revenue Account on the
Repayment Date to which such Calculation Date relates, (i) in the event that
the conditions to distributions set forth in Sections 6.6(a) and 6.6(b) have
been satisfied, for payment to Borrower or distribution by Borrower as it may
determine in its sole discretion, (ii) in the event that the conditions to
distributions set forth in Section 6.6(b) are not satisfied, to the
Distribution Suspense Account for application as provided in Section 7.10, and
(iii) in the event that the conditions to distributions set forth in Section
6.6(b) are satisfied but those set forth in Section 6.6(a) are not satisfied,
to the Initial Distribution Suspense Account for application as provided in
Section 7.10.
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7.2.2 O&M Costs. On or before the fifth Banking
Day prior to the last Banking Day of each month during which Borrower desires
to transfer sums to the Operating Account for the payment of Senior O&M Costs,
Borrower shall submit to the Agent a certificate in the form of Exhibit C-7
detailing the amounts to be so transferred ("Disbursement Requisition"), which
amounts shall not exceed the Senior O&M Costs which have become, or are
anticipated to become, due and payable during such month, excluding Major
Maintenance costs funded from the Major Maintenance Reserve Account. Agent
shall review such Disbursement Requisition within five Banking Days following
receipt thereof, and shall transfer the amounts specified therein to the
Operating Account for application in accordance with Waterfall Level 1 to the
extent that such expenditures are in accordance with the terms of the Annual
Operating Budget and this Agreement, as such budget may be exceeded pursuant to
the terms hereof. Notwithstanding anything in this Section 7.2.2 to the
contrary, the transfers to, and expenditures from, the Revenue Account for
Senior O&M Costs (other than fuel costs as provided in Section 5.15.2 and O&M
Costs incurred in an emergency) payable pursuant to Waterfall Level 1 (a) with
respect to any Major Budget Category, shall not without Agent's consent exceed
on an annual year-to-date basis 105% of the amounts specified in such Major
Budget Category and (b) with respect to any Budget Category, shall not without
Agent's consent exceed on an annual year-to-date basis 110% of the amounts
specified in such Budget Category, in each case, as set forth in the
then-applicable Annual Operating Budget (net of amounts set forth therein for
Subordinated O&M Costs and Subordinated Fuel Costs). Notwithstanding anything
to the contrary in this Agreement, in no event shall the "Annual Base Fee" (as
defined in the O&M Agreement) be greater than the amount specified therefor in
the then-applicable Annual Operating Budget. Borrower shall promptly pay all
Senior O&M Costs in excess of the amounts permitted under the preceding
sentence from amounts, if any, of Available Cash, or by contribution of
additional equity funds; provided, however, that if Agent subsequently approves
a variation in such Annual Operating Budget which would have allowed the
payment of such excess Senior O&M Costs, Borrower shall be entitled to recover
any such Senior O&M Costs previously paid by the contribution of additional
equity funds from Project Operating Revenues at Waterfall Level 1. Each
Disbursement Requisition shall reflect a reduction in the Senior O&M Costs for
which Borrower requests that funds be transferred to the Operating Account
during such month for any amounts which remain, or are expected to remain, in
the Operating Account at the end of any month as a result of a previous
Disbursement Requisition.
7.2.3 Subordinated Fuel Costs. On or before the
fifth Banking Day prior to each Repayment Date on which Borrower desires to
make payments of Subordinated Fuel Costs, Borrower shall include in the
Disbursement Requisition submitted pursuant to Section 7.2.2 on such date the
amounts to be so paid, which amounts shall not exceed the Subordinated Fuel
Costs which have become due and payable. Agent shall review such Disbursement
Requisition within five Banking Days following receipt thereof, and, to the
extent funds exist in the Revenue Account after application of amounts in such
account to Waterfall Levels 1 through 8, make payment of the Subordinated Fuel
Costs specified therein to the designated payee thereof to the extent that such
expenditures are in accordance with the terms of the Annual Operating Budget.
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7.2.4 Subordinated O&M Costs. On or before the
fifth Banking Day prior to each Repayment Date on which Borrower desires to
make payments of Subordinated O&M Costs, Borrower shall include in the
Disbursement Requisition submitted pursuant to Section 7.2.2 on such date the
amounts to be so paid, which amounts shall not exceed the Subordinated O&M
Costs which have become due and payable. Agent shall review such Disbursement
Requisition within five Banking Days following receipt thereof, and, to the
extent funds exist in the Revenue Account after application of amounts in such
account to Waterfall Levels 1 through 9, make payment of the Subordinated O&M
Costs specified therein to the designated payee thereof to the extent that such
expenditures are in accordance with the terms of the Annual Operating Budget.
7.2.5 Mandatory Prepayment.
(a) If, on any Repayment Date, an Event
of Default shall exist, Borrower shall use all Available Cash on such Repayment
Date (i) to prepay the Loans in inverse order of maturity and (ii) upon
repayment in full of the Loans, to repay all other Obligations of Borrower to
the Banks, as designated by Agent and the Required Banks.
(b) If, on any Extension Determination
Date, the Extension Requirements are not met, Borrower shall, on each Repayment
Date thereafter until the Extension Requirements have been satisfied, use all
Available Cash on such Repayment Dates (i) to prepay the Loans in inverse order
of maturity and (ii) upon repayment in full of the Loans, to repay all other
Obligations of Borrower to the Banks, as designated by Agent and the Required
Banks.
(c) Subject to Sections 7.2.5(a) and
7.2.5(b), if on any Calculation Date during the Term Period the Four-Quarter
Average Debt Service Coverage Ratio for the Repayment Date to which such
Calculation Date relates shall be less than 1.75 to 1.00, Borrower shall use
50% of the Available Cash on such Calculation Date (i) to prepay the Loans in
inverse order of maturity and (ii) upon repayment in full of the Loans, to
repay all other Obligations of Borrower to the Banks, as designated by Agent
and the Required Banks.
(d) Subject to Sections 7.2.5(a) and
7.2.5(b), if on any Calculation Date during the Term Period the Four-Quarter
Average Debt Service Coverage Ratio for the Repayment Date to which such
Calculation Date relates shall be less than 2.00 to 1.00 but shall exceed or
equal 1.75 to 1.00, Borrower shall use fifteen (15%) of the Available Cash on
such Calculation Date (i) to prepay the Loans in inverse order of maturity and
(ii) upon repayment in full of the Loans, to repay all other Obligations of
Borrower to the Banks, as designated by Agent and the Required Banks.
(e) Nothing in this Section 7.2.5 shall
limit in any manner the rights and remedies of Agent and the Banks upon and
during the continuation of an Event of Default under this Agreement.
7.3 Major Maintenance Reserve Account.
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7.3.1 Establishment of Account. On or prior to
Term-Conversion, Borrower and Agent shall establish the Major Maintenance
Reserve Account at the Depositary Agent's New York office.
7.3.2 Funding. On each Repayment Date (other than
Term-Conversion), Borrower shall cause all amounts then in the Revenue Account
in excess of the amounts applied through Waterfall Level 5 to be deposited into
the Major Maintenance Reserve Account, up to an amount equal to the sum of (a)
the Major Maintenance Reserve Requirement plus (b) an amount (without
duplication) up to the aggregate amount, if any, by which Borrower failed to
fund the Major Maintenance Reserve Account on any prior Repayment Date as
required under this Section 7.3.2.
7.3.3 Withdrawals. Borrower shall be entitled to
submit a duly executed Reserve Account Disbursement Requisition in
substantially the form of Exhibit C-8 (a "Reserve Account Disbursement
Requisition") in order to withdraw amounts from the Major Maintenance Reserve
Account to pay all fees, costs, charges and other amounts due in connection
with any Major Maintenance in accordance with the projected Major Maintenance
expenses contained in the Annual Operating Budget, or as otherwise approved by
the Agent and the Independent Engineer.
7.3.4 Earnings. All earnings on monies in the
Major Maintenance Reserve Account shall accrue to the Major Maintenance Reserve
Account up to the amount required under Section 7.3.2 and shall thereafter be
deposited in the Reserve Account.
7.4 Emissions Offsets Reserve Account.
7.4.1 Establishment of Account. On or prior to
Term-Conversion, Borrower and Agent shall establish the Emissions Offsets
Reserve Account at the Depositary Agent's New York office. On the date of
Term-Conversion, Borrower shall deposit or cause to be deposited into the
Emissions Offsets Reserve Account an amount equal to Eight Hundred Thousand
Dollars ($800,000) which amount shall be obtained, to the extent funds are
available, through a transfer from the Construction Account as provided in
Section 7.1.4.
7.4.2 Withdrawals. Borrower shall be entitled to
submit a duly executed Reserve Account Disbursement Requisition in
substantially the form of Exhibit C-8 in order to withdraw amounts from the
Emissions Offsets Reserve Account to pay all fees, costs, charges and other
amounts incurred in connection with the acquisition of any required Emissions
Offsets Credits.
7.4.3 Earnings. All earnings on monies in the
Emissions Offsets Reserve Account shall accrue to the Emissions Offsets Reserve
Account.
7.4.4 Letters of Credit. In lieu of depositing
cash in the Emissions Offsets Reserve Account pursuant to Section 7.4.1,
Borrower may provide an unconditional, irrevocable
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direct-pay letter of credit (the "Emissions Offsets Reserve Letter of Credit")
issued in a stated amount equal to the EORA Minimum Balance for the account of
Borrower by a financial institution rated at least A or the equivalent thereof
by S&P or at least A2 or the equivalent thereof by Moody's and otherwise
approved by Agent, naming the Agent on behalf of the Banks as the beneficiary,
and containing terms and provisions satisfactory to Agent in its sole
discretion. Upon delivery of the Emissions Offsets Reserve Letter of Credit to
Agent, all cash in the Emissions Offsets Reserve Account shall be released to
Borrower. In addition to and without limiting the foregoing, the Emissions
Offsets Reserve Letter of Credit (a) shall have an initial expiration date of
at least one (1) year after the date of issuance and (b) shall not be secured
by any of the Collateral. Further, the fees and reimbursement obligations in
respect of the Emissions Offsets Reserve Letter of Credit shall not be recourse
to Borrower or the Project. On each anniversary of the issuance of the
Emissions Offsets Reserve Letter of Credit, Borrower shall cause the stated
amount of the Emissions Offsets Reserve Letter of Credit to be increased to the
EORA Minimum Balance as of such date. If no agreement for a renewal or
replacement of the Emissions Offsets Reserve Letter of Credit has been made
thirty (30) days prior to the expiration of the Emissions Offsets Reserve
Letter of Credit, the Agent may draw the entire undrawn amount of the Emissions
Offsets Reserve Letter of Credit and deposit such drawing in the Emissions
Offsets Reserve Account or Borrower shall deposit cash in the Emissions Offsets
Reserve Account in the amount of the Emissions Offsets Reserve Letter of
Credit. Fees, costs, expenses and reimbursement obligations relating to any
Emissions Offsets Reserve Letter of Credit shall be paid only out of any funds
distributed to Borrower under Waterfall Level 11.
7.4.5 Release of Funds. Funds in the Emissions
Offsets Reserve Account shall be transferred to the Revenue Account for
application as provided in Section 7.2.1 upon the earlier of the following to
occur: (a) Borrower has demonstrated to the reasonable satisfaction of the
Majority Banks that Borrower owns, free and clear of any Liens, Emissions
Offsets Credits, in final and nonappealable form, in compliance with all Legal
Requirements and to the satisfaction of the Texas Natural Resource Conservation
Commission (the "TNRCC") to enable the Project to be operated at 240 MW based
on the availability factor set forth in the Base Case Project Projections; or
(b) Borrower has demonstrated to the reasonable satisfaction of the Majority
Banks (including an opinion of counsel) that Borrower is no longer subject to
any Legal Requirements to obtain such Emissions Offsets Credits because (i)
either (A) there is a final, nonappealable redesignation under the federal
Clean Air Act of 1970, as amended in 1977 and 1990, 42 U.S.C. Section 7401 et
seq., of the air quality control region within which the Project is located
from a non- attainment area with respect to ozone to an attainment or
unclassifiable area or (B) there is a final, nonappealable repeal, modification
or permanent suspension of all Governmental Rules which require the Emission
Offsets Credits, and (ii) there neither exists nor has there been proposed any
other Legal Requirement that could reasonably be expected to require the
Project to obtain such Emissions Offsets Credits. If, at such time as funds in
the Emissions Offsets Reserve Account would be transferred to the Revenue
Account pursuant to this Section 7.4.5, Borrower has provided Agent with an
Emissions Offsets Reserve Letter of Credit, then, at such time, Agent shall
draw the entire undrawn stated amount of the Emissions Offsets Reserve Letter
of Credit and deposit the proceeds of such draw into the Revenue Account for
application pursuant to Section 7.2.1.
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7.5 Fuel Supply Reserve Account.
7.5.1 Establishment of Account. On or prior to
Term-Conversion, Borrower and Agent shall establish the Fuel Supply Reserve
Account at the Depositary Agent's New York office. On the date of
Term-Conversion, Borrower shall deposit or cause to be deposited into the Fuel
Supply Reserve Account an amount equal to the FSRA Minimum Balance, which
amount shall be obtained, to the extent funds are available, through a transfer
from the Construction Account as provided in Section 7.1.4.
7.5.2 Withdrawals. Amounts on deposit in the Fuel
Supply Reserve Account shall be withdrawn as Agent and Borrower may agree.
7.5.3 Earnings. All earnings on monies in the Fuel
Supply Reserve Account shall accrue to the Fuel Supply Reserve Account.
7.5.4 Letters of Credit. In lieu of depositing
cash in the Fuel Supply Reserve Account pursuant to Section 7.5.1, Borrower may
provide an unconditional, irrevocable direct-pay letter of credit (the "Fuel
Supply Reserve Letter of Credit") issued in a stated amount equal to FSRA
Minimum Balance for the account of Borrower by a financial institution rated at
least A or the equivalent thereof by S&P or at least A2 or the equivalent
thereof by Moody's and otherwise approved by Agent, naming the Agent on behalf
of the Banks as the beneficiary, and containing terms and provisions
satisfactory to Agent in its sole discretion. Upon delivery of the Fuel Supply
Reserve Letter of Credit to Agent, all cash in the Fuel Supply Reserve Account
shall be released to Borrower. In addition to and without limiting the
foregoing, the Fuel Supply Reserve Letter of Credit (a) shall have an initial
expiration date of at least one (1) year after the date of issuance and (b)
shall not be secured by any of the Collateral. Further, the fees and
reimbursement obligations in respect of the Fuel Supply Reserve Letter of
Credit shall not be recourse to Borrower or the Project. On each anniversary
of the issuance of the Fuel Supply Reserve Letter of Credit, Borrower shall
cause the stated amount of the Fuel Supply Reserve Letter of Credit to be
increased to the FSRA Minimum Balance as of such date. If no agreement for a
renewal or replacement of the Fuel Supply Reserve Letter of Credit has been
made thirty (30) days prior to the expiration of the Fuel Supply Reserve Letter
of Credit, Agent may draw the entire undrawn amount of the Fuel Supply Reserve
Letter of Credit and deposit such drawing in the Fuel Supply Reserve Account or
Borrower shall deposit cash in the Fuel Supply Reserve Account in the amount of
the Fuel Supply Reserve Letter of Credit. Fees, costs, expenses and
reimbursement obligations relating to any Fuel Supply Reserve Letter of Credit
shall be paid only out of any funds distributed to Borrower under Waterfall
Level 11.
7.5.5 Release of Funds. Agent shall cause any
funds remaining in the Fuel Supply Reserve Account on the tenth (10th)
anniversary of the Commercial Operation Date promptly to be transferred to the
Revenue Account and applied pursuant to Section 7.2.1. If, at such time as
funds in the Fuel Supply Reserve Account would be transferred to the Revenue
Account pursuant to this Section 7.5.5, Borrower has provided Agent with a Fuel
Supply Reserve Letter of Credit, then, at such time, Agent shall draw the
entire undrawn stated amount of the
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Fuel Supply Reserve Letter of Credit and deposit the proceeds of such draw into
the Revenue Account for application pursuant to Section 7.2.1.
7.6 Debt Service Reserve Account.
7.6.1 Establishment of Account. On or prior to
Term-Conversion, Borrower and Agent shall establish the Debt Service Reserve
Account at the Depositary Agent's New York office. On the date of
Term-Conversion, Borrower shall deposit or cause to be deposited into the Debt
Service Reserve Account an amount equal to the DSRA Minimum Balance, which
amount shall be obtained, to the extent funds are available, through a transfer
from the Construction Account as provided in Section 7.1.4.
7.6.2 Funding. After Term-Conversion, on each
Repayment Date, if the balance in the Debt Service Reserve Account is not equal
to or greater than the DSRA Minimum Balance, Borrower shall cause all amounts
then in the Revenue Account on the applicable Repayment Date in excess of the
amounts applied through Waterfall Level 6 to be deposited into the Debt Service
Reserve Account until the amount deposited therein equals the DSRA Minimum
Balance.
7.6.3 Replenishment of Account. In the event that
on any Repayment Date the balance in the Debt Service Reserve Account is less
than the DSRA Minimum Balance, then on each Repayment Date thereafter until the
balance in the Debt Service Reserve Account is equal to the DSRA Minimum
Balance, Borrower shall cause all amounts then in the Revenue Account on the
applicable Repayment Date in excess of the amounts applied through Waterfall
Level 6 to be deposited into the Debt Service Reserve Account.
7.6.4 Withdrawals. Agent shall withdraw amounts
from the Debt Service Reserve Account to pay (a) fees, costs, charges and other
amounts due to Agent and the Banks and to pay amounts of principal and interest
due under the Loans in the event that amounts in the Revenue Account are
insufficient therefor, and (b) if approved by the Majority Banks in their
reasonable discretion, O&M Costs.
7.6.5 Earnings. All earnings on monies in the Debt
Service Reserve Account shall accrue to the Debt Service Reserve Account until
such time as the Debt Service Reserve Account has on deposit therein an amount
equal to the DSRA Minimum Balance, whereupon all amounts in the Debt Service
Reserve Account in excess of such amount shall be deposited in the Revenue
Account as Project Operating Revenues on a monthly basis.
7.6.6 Letters of Credit. In lieu of depositing
cash in the Debt Service Reserve Account pursuant to Section 7.6.1, 7.6.2 and
7.6.3, Borrower may provide an unconditional, irrevocable direct-pay letter of
credit (the "Debt Service Reserve Letter of Credit") issued in a face amount
equal from time to time to or, to the extent cash is deposited, less than, the
DSRA Minimum Balance for the account of Borrower by a financial institution
rated at least A or the equivalent thereof by S&P or at least A2 or the
equivalent thereof by Moody's and
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otherwise approved by Agent, naming the Agent on behalf of the Banks as the
beneficiary, and containing terms and provisions satisfactory to Agent in its
sole discretion. To the extent the stated amount of the Debt Service Reserve
Letter of Credit plus amounts on deposit in the Debt Service Reserve Account
exceed the DSRA Minimum Balance, cash in the Debt Service Reserve Account shall
be released to Borrower. In addition to and without limiting the foregoing,
the Debt Service Reserve Letter of Credit (a) shall have an initial expiration
date of at least one (1) year after the date of issuance and (b) shall not be
secured by any of the Collateral. Further, the fees and reimbursement
obligations in respect of the Debt Service Reserve Letter of Credit shall not
be recourse to Borrower or the Project. If no agreement for a renewal or
replacement of the Debt Service Reserve Letter of Credit has been made thirty
(30) days prior to the expiration of the Debt Service Reserve Letter of Credit,
the Agent may draw the entire undrawn amount of the Debt Service Reserve Letter
of Credit and deposit such drawing in the Debt Service Reserve Account or
Borrower shall deposit cash in the Debt Service Reserve Account in the amount
of the Debt Service Reserve Letter of Credit. Fees, costs, expenses and
reimbursement obligations relating to any Debt Service Reserve Letter of Credit
shall be paid only out of any funds distributed to Borrower under Waterfall
Level 11.
7.7 Operating Account.
7.7.1 Establishment of Account. On or prior to
Term-Conversion, Borrower and Agent shall establish at Union Bank of California
an account entitled "Pasadena Project -- Operating Account" ("Operating
Account").
7.7.2 Funding. From time to time, in accordance
with the provisions of Waterfall Levels 1 and 10, Borrower shall cause to be
transferred to the Operating Account the amounts specified in Sections 7.2.1
and 7.2.2.
7.7.3 Withdrawals. Borrower shall be entitled to
withdraw amounts from the Operating Account to pay Senior O&M Costs which have
become due and payable in accordance with the Disbursement Requisition in which
such Senior O&M Costs were described. Amounts transferred to the Operating
Account which are not, for any reason, applied to payment of Senior O&M Costs
in accordance with the Disbursement Requisition pursuant to which such amounts
were transferred, shall be retained in the Operating Account for application to
the following month's Senior O&M Costs in accordance with Section 7.2.2.
7.8 Loss Proceeds Account. On or prior to the Closing
Date, Borrower and Agent shall establish at the Depository Agent's New York
Office the Loss Proceeds Account. All Insurance Proceeds, Eminent Domain
Proceeds and damage payments described in Section 7.13 shall be deposited in
the Loss Proceeds Account and applied (a) as specified in Sections 7.11 through
7.13 and (b) if no such application is specified, to the prepayment of the
Loans in inverse order of maturity, and thereafter to payment of all other
Obligations of Borrower.
7.9 Accrual Sub-Account.
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7.9.1 Establishment of Sub-Account. On or before
Term-Conversion, Borrower shall establish the Accrual Sub-Account at the
Depositary Agent's New York office. On the last Banking Day of each month
following Term-Conversion, Borrower shall deposit or cause to be deposited into
the Accrual Sub-Account from amounts available for application thereto, under
the priority of payments set forth in Section 7.2.2, (a) the amount of any
Senior O&M Costs, which, in accordance with the then applicable Annual
Operating Budget, are to be accrued, and not paid, during the following month
and (b) a prudent and sufficient level of working capital and reserves for the
Project, taking into account projected levels of Project Revenues, O&M Costs
and amounts on deposit in the Revenue Account for a period of approximately
forty-five (45) days to pay any other amounts which will become due and payable
during the ensuing Repayment Period.
7.9.2 Withdrawals. Amounts from the Accrual
Sub-Account may be transferred from time to time at Borrower's request to the
Revenue Account for payment of accrued Senior O&M Costs and other costs and
expenses with respect to which amounts were deposited in the Accrual
Sub-Account in accordance with Section 7.2.1. Amounts on deposit in the
Accrual Sub-Account which were deposited in anticipation of accrued obligations
which for any reason did not become payable when so scheduled to be paid shall
be released into the Revenue Account on the Repayment Date immediately
following the date upon which the anticipated accrued liability was expected to
become due and payable.
7.9.3 Earnings. Investment income from Permitted
Investments of amounts on deposit in the Accrual Sub- Account shall be deemed
Project Operating Revenues for purposes of calculating Debt Service Coverage
Ratios, and shall be transferred to the Revenue Account on a monthly basis.
7.10 Distribution Suspense Account; Initial Distribution
Suspense Account.
7.10.1 Establishment of Account. On or prior to
Term-Conversion, Borrower and Agent shall establish the Distribution Suspense
Account and the Initial Distribution Suspense Account at the Depositary Agent's
New York office.
7.10.2 Funding. From time to time, Agent shall
cause to be transferred to the Distribution Suspense Account and the Initial
Distribution Suspense Account, the amounts specified in Waterfall Level 11.
7.10.3 Withdrawals.
(a) Distribution Suspense Account. (i)
Until the funds in the Distribution Suspense Account have been applied as
provided in Section 7.10.3(a)(ii), Agent shall withdraw amounts from the
Distribution Suspense Account to pay all fees, charges, costs and other amounts
specified in Waterfall Levels 1 through 8, in such order, to the extent that
amounts in the Revenue Account are insufficient therefor.
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(ii) Upon the satisfaction, on four
consecutive Calculation Dates, of each of the conditions to distribution set
forth in Section 6.6(b), all funds in the Distribution Suspense Account shall
be paid to, or as directed by, Borrower as it may determine in its sole
discretion; provided, however, that in the event that all such conditions have
not been so satisfied, as of the fourth Repayment Date occurring after the
deposit of funds in the Distribution Suspense Account, then such funds
remaining in the Distribution Suspense Account (after any withdrawals made
pursuant to Section 7.10.3(a)(i)) shall be used (x) to prepay the Loans in
inverse order of maturity and (y) upon repayment in full of the Loans, to repay
all other Obligations of Borrower to the Banks, as designated by Agent and the
Required Banks. For purposes of determining whether four Repayment Dates have
occurred since the deposit of any funds in the Distribution Suspense Account,
all withdrawals made pursuant to Section 7.10.3(a)(i) shall be deemed to have
been made on a first-in first-out basis.
(b) Initial Distribution Suspense
Account. (i) Until the funds in the Initial Distribution Suspense Account have
been applied as provided in Section 7.10.3(b)(ii), Agent shall, upon Borrower's
request, withdraw funds from the Initial Distribution Suspense Account to pay
Subordinated Fuel Costs to the extent funds in the Revenue Account are
insufficient therefor.
(ii) Upon satisfaction of each of the
conditions to distribution set forth in Section 6.6(a), all funds in the
Initial Distribution Suspense Account shall be paid to, or as directed by,
Borrower as it may determine in its sole discretion.
7.11 Application of Insurance Proceeds.
7.11.1 General. Borrower shall notify Agent of any
casualty and keep Agent timely apprised of insurance claim proceedings. All
amounts and proceeds (including instruments) in respect of the proceeds of any
insurance policy required to be maintained by Borrower hereunder ("Insurance
Proceeds") shall be applied as provided in this Section 7.11. All Insurance
Proceeds shall be paid by the insurers directly to Agent (as loss payee or
additional insured as provided in Exhibit K). If any Insurance Proceeds are
paid directly to Borrower or Calpine with respect to Project by any insurer,
such Insurance Proceeds shall be received only in trust for Agent, shall be
segregated from other funds of Borrower or Calpine, as the case may be, and
shall be forthwith paid over to Agent in the same form as received (with any
necessary endorsement). To the fullest extent that it effectively may do so
under applicable law, Agent shall apply all such Insurance Proceeds in
accordance with the provisions of this Section 7.11.
7.11.2 Business Interruption Insurance. Any
business interruption Insurance Proceeds received by Agent or Borrower shall be
deposited into the Revenue Account for application in accordance with Section
7.2 (provided that Borrower may not apply such Insurance Proceeds toward
payment of the items described in Waterfall Level 10 or 11 without the consent
of the Majority Banks).
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7.11.3 Applications; Mandatory Prepayments. All
Insurance Proceeds (other than those described in Sections 7.11.2 and 7.11.4)
and all Eminent Domain Proceeds shall be applied (a) to the prepayment of Loans
in inverse order of maturity, and (b) to the payment of all other Obligations
of Borrower, unless each of the following conditions are satisfied or waived by
the Agent, or the Required Banks, as required pursuant to Section 7.11.5 or
7.11.6, in which event such amounts shall be applied to the repair or
restoration of the Project in accordance with the terms of such subsections:
(a) such damage or destruction does not
constitute the destruction of all or substantially all of the man-made portion
of the Project;
(b) no Inchoate Default or Event of
Default has occurred and is continuing and after giving effect to any proposed
repair and restoration, such damage or destruction or proposed repair and
restoration will not result in an Event of Default or an Inchoate Default;
(c) Borrower and the Independent
Engineer certify, and Agent (with, if applicable, the consent of the Required
Banks) determines in its reasonable judgment, that repair or restoration of the
Project is technically and economically feasible within a six-month period and
that a sufficient amount of funds is or will be available to Borrower to make
repairs and restorations;
(d) Borrower and the Independent
Engineer certify, and Agent (with, if applicable, the consent of the Required
Banks) determines in its reasonable judgment, that a sufficient amount of funds
is or will be available to Borrower and to make all payments of Debt Service
which will become due during and following repair period and to maintain the
Debt Service Coverage Ratios set forth in the Base Case Project Projections as
in effect on the Closing Date, unless the Required Banks agree otherwise;
(e) if such damage or destruction occurs
during construction, such repair or restoration will not adversely affect, in
the reasonable judgment of Agent in consultation with the Independent Engineer,
achievement of Completion by the Construction Loan Maturity Date;
(f) no Permit is necessary to proceed
with the repair and restoration and no material amendment to the Project
Documents, or, except with the consent of the Required Banks, this Agreement or
any of the Credit Documents, and no other instrument is necessary for the
purpose of effecting the repairs or restorations or subjecting the repairs or
restorations to the Liens of the Collateral Documents and maintaining the
priority of such Liens or, if any of the above is necessary, Borrower will be
able to obtain the same as and when required;
(g) Agent shall receive an opinion of
counsel acceptable to Agent opining as to the Permits described in paragraph
(f) above, and an opinion to the effect that such
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repairs or restoration will be subject to the Liens of the Collateral Documents
at the same level of priority as the other Collateral; and
(h) Agent shall receive such additional
title insurance, title insurance endorsements, mechanic's lien waivers,
certificates, opinions or other matters as it may reasonably request as
necessary or appropriate in connection with such repairs or restoration or to
preserve or protect the Banks' interests hereunder and in the Collateral.
7.11.4 Proceeds Less than $1,000,000. If there
shall occur any damage or destruction of the Project with respect to which
Insurance Proceeds for any single loss not in excess of $1,000,000 are payable,
such Insurance Proceeds shall be held by the Agent in the Loss Proceeds Account
and released by Agent to the Borrower in accordance with Section 7.11.7.
7.11.5 Proceeds in Excess of $1,000,000, Not in
Excess of $5,000,000. Provided that the conditions set forth in Section 7.11.3
have been waived by the Agent and the Independent Engineer, or have been
acknowledged by such Persons as having been satisfied, if there shall occur any
damage or destruction of the Project with respect to which Insurance Proceeds
for any single loss in excess of $1,000,000, but not in excess of $5,000,000,
are payable, such Insurance Proceeds shall be held by the Agent in the Loss
Proceeds Account and released by Agent to the Borrower in accordance with
Section 7.11.7.
7.11.6 Proceeds in Excess of $5,000,000. Provided
that the conditions set forth in Section 7.11.3 have been waived by the Agent,
the Required Banks and the Independent Engineer, or have been acknowledged by
such Persons as having been satisfied, if there shall occur any damage or
destruction of the Project with respect to which Insurance Proceeds for any
single loss in excess of $5,000,000 are payable, such Insurance Proceeds shall
be held by the Agent in the Loss Proceeds Account and released by Agent to the
Borrower in accordance with Section 7.11.7.
7.11.7 Repair and Restoration Procedures. Amounts
which are to be applied to repair or restoration of the Project pursuant to
this Section 7.11 shall be disbursed by Agent from the Loss Proceeds Account in
accordance with the following procedures:
(a) Borrower shall cause any repairs or
restoration to be commenced and completed promptly and diligently at the cost
and expense of Borrower;
(b) From time to time (after the Agent
or the Required Banks, if applicable, shall have duly approved the making of
such repairs or restoration), Agent's authorization of release of Insurance
Proceeds for application toward such repairs or restoration shall be
conditioned upon Borrower's written request and the presentation to Agent of
all documents, certificates and information with respect to such Insurance
Proceeds which would be required in order to obtain a Construction Loan under
this Agreement, including a certificate from Borrower (i) describing in
reasonable detail the nature of the repairs or restoration to be effected with
such release, (ii) stating the cost of such repairs or restoration and the
specific amount
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requested to be paid over to or upon the order of Borrower and that such amount
is requested to pay the cost thereof, (iii) stating that the aggregate amount
requested by Borrower in respect of such repairs or restoration (when added to
any other Insurance Proceeds received by Borrower in respect of such damage or
destruction) does not exceed the cost of such repairs or restoration and that a
sufficient amount of funds is or will be available to Borrower to complete the
Project, and (iv) stating that no Inchoate Default has occurred and is
continuing other than an Event of Default resulting solely from such damage or
destruction.
7.11.8 Excess Insurance Proceeds. If, after
Insurance Proceeds have been applied to the repair or restoration of the
Project as provided in Sections 7.11.4, 7.11.5 or 7.11.6, the Banks in
consultation with the Independent Consultants determine that the Project will
be able to operate at a level enabling Borrower to satisfy its obligations
hereunder as well as before the damage or destruction, any excess Insurance
Proceeds shall be paid into the Revenue Account. In the event that the Banks
in consultation with the Independent Engineer determine otherwise, such excess
Insurance Proceeds shall be applied (a) to the prepayment of Loans in such
order as will enable the Project to operate at a level enabling Borrower to
satisfy its obligations hereunder as well as before the damage and destruction
and thereafter in inverse order of maturity, and (b) to the payment of all
other Obligations of Borrower.
7.11.9 Events of Default. If an Event of Default
shall have occurred and be continuing, then any provisions of this Sections
7.11 to the contrary notwithstanding, the Insurance Proceeds (including any
Permitted Investments made with such proceeds, which shall be liquidated in
such manner as the Banks shall deem reasonable and prudent under the
circumstances) may be applied by Agent (a) to curing such Event of Default, and
any Insurance Proceeds remaining thereafter shall be applied as provided in
this Section 7.11 or (b) if such Event of Default cannot be cured, toward
payment of all other Obligations of Borrower, in connection with exercise of
the Banks' remedies pursuant to Article 8.
7.12 Application of Eminent Domain Proceeds. All amounts
and proceeds (including instruments) received in respect of any Event of
Eminent Domain ("Eminent Domain Proceeds") shall be subject to the same
treatment as Insurance Proceeds as provided in Section 7.10.
7.13 Application of Certain Damages Payments; Mandatory
Prepayments.
7.13.1 Contractor. Delay related Liquidated Damages
shall be deposited in the Construction Account and applied pursuant to Section
7.1.4. Performance related Liquidated Damages received before Term-Conversion
shall be applied to the prepayment of Construction Loans in accordance with
Section 2.1.7. Performance related Liquidated Damages received after Term-
Conversion shall be applied first to the prepayment of Term Loans in accordance
with Section 2.1.7 and thereafter to all other Obligations of Borrower.
7.13.2 Power Purchasers. Any damage payments made
by Phillips, HL&P, Power Marketer, or any other purchaser of the power
generated by the Project in
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satisfaction of such party's obligations under its purchase agreement shall (a)
to the extent such damages are intended to replace lost revenues, be deposited
in the Revenue Account for application as provided in Section 7.2, and (b)
otherwise, be deposited in the Loss Proceeds Account and (i) applied to the
prepayment of (A) prior to Term-Conversion, Construction Loans, and (B)
following Term-Conversion, Term Loans in inverse order of maturity and (ii) to
the extent that all such Construction Loans or Term Loans, as applicable, have
been prepaid, applied to the other Obligations of Borrower.
7.13.3 Other. Except as otherwise expressly
permitted under this Agreement, including this Section 7.13, Borrower shall
apply the proceeds of any other surety, performance or similar bonds and any
other liquidated or other damages paid in respect of damage payments or
performance payments by any contractors or subcontractors or other Persons
involved in the construction and operation of the Project, to the prepayment of
the Loans in inverse order of maturity, and thereafter to the Obligations of
Borrower or, with the prior written consent of Agent acting in consultation
with the Independent Engineer, to such other application in relation to the
Project as Borrower may request.
7.14 Security Interest in Proceeds and Accounts. Borrower
hereby pledges, assigns and transfers to the Agent on behalf of the Banks and
grants to Agent on behalf of the Banks a security interest in and to all
Insurance Proceeds and Eminent Domain Proceeds (collectively, "Proceeds"),
Accounts, and contents of Accounts, as security for the Loans and the full and
faithful performance of all of Borrower's obligations hereunder and under the
other Credit Documents. Borrower shall not have any rights or powers with
respect to any Account except to have funds on deposit therein applied or
distributed to Borrower in accordance with this Agreement. Agent is hereby
authorized to reduce to cash any Permitted Investment (without regard to
maturity) in order to make any application required by any section of this
Article 7 or otherwise pursuant to the Credit Documents. Upon the occurrence
and during the continuance of an Event of Default, Agent shall have all rights
and powers with respect to Proceeds, the Accounts and the contents of the
Accounts as it has with respect to any other Collateral and may apply such
amounts to the payment of interest, principal, fees, costs, charges or other
amounts due or payable to Agent or the Banks with respect to the Loans in such
order as the Majority Banks may elect in their sole discretion. If such Event
of Default occurs prior to Term-Conversion, until such time as the Majority
Banks so elect to exercise such rights and powers, amounts in the Revenue
Account constituting Project Operating Revenues shall continue to be applied by
Agent to Pre-Conversion Senior O&M Costs to the extent that Agent so elects in
its sole discretion. If such Event of Default occurs following
Term-Conversion, until such time as the Required Banks so elect to exercise
such rights and powers, amounts in the Revenue Account shall continue to be
applied by Agent to the payment categories specified in Waterfall Levels 1 (to
the extent of actual Senior O&M Costs payable to third parties that are not
Affiliates of Borrower) and 2 through 7, and, to the extent that Agent so
elects in its sole discretion, Waterfall Levels 1, 8, 9, 10 and 11. Borrower
shall not have any rights or powers with respect to such amounts except as
expressly provided in this Article 7.
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7.15 Permitted Investments. All amounts held by Borrower
and/or Agent in the Accounts or as Insurance Proceeds or Eminent Domain
Proceeds shall only be invested in Permitted Investments as provided in the
Depositary Agreement. Borrower shall not hold funds in any accounts other than
the Accounts; provided that Borrower shall be permitted to maintain the
Operating Account in accordance with Section 7.7.
7.16 Earnings on Accounts. Except as otherwise expressly
provided herein, including with respect to the Revenue Account and the
Operating Account, all earnings on funds in any Account maintained hereunder
shall, on each Repayment Date, be deposited in the Revenue Account as Project
Operating Revenues.
7.17 Dominion and Control. Each of the Accounts and the
amounts held thereunder (including Permitted Investments therein), except for
the Operating Account, shall at all times be under the exclusive dominion and
control of the Depository Agent.
7.18 Termination of Commitments. Upon repayment in full
of all Obligations and expiration or irrevocable termination of all
Commitments, Agent shall disburse any amounts on deposit in the Accounts to
Borrower, or, if applicable, as directed by a court of competent jurisdiction.
ARTICLE 8 - EVENTS OF DEFAULT; REMEDIES
8.1 Events of Default.
The occurrence of any of the following events shall
constitute an event of default ("Events of Default") hereunder:
8.1.1 Failure to Make Payments. Borrower shall
fail to pay, in accordance with the terms of this Agreement, (a) any principal
on any Loan on the date that such sum is due, (b) any interest on any Loan or
any scheduled fee, cost, charge or sum due hereunder or under the other Credit
Documents, within three (3) days after the date that such sum is due, or (c)
any other fee, cost, charge or other sum due under this Agreement within five
(5) days after written notice that such sum is due and has not been paid.
8.1.2 Judgments. A final judgment or judgments
shall be entered against Borrower or any Partner in the amount of $1,000,000 or
more individually or in the aggregate (other than (a) a judgment which is fully
covered by insurance or discharged within 30 days after its entry, or (b) a
judgment, the execution of which is effectively stayed within 30 days after its
entry but only for 30 days after the date on which such stay is terminated or
expires) or which if left unstayed could reasonably be expected to have a
Material Adverse Effect.
8.1.3 Misstatements; Omissions. Any financial
statement, representation, warranty or certificate made or prepared by, under
the control of or on behalf of Borrower and furnished to Agent or any Bank
pursuant to this Agreement, or in any separate statement or
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document to be delivered to Agent or any Bank hereunder or under any other
Credit Document, shall contain an untrue or misleading statement of a material
fact or shall fail to state a material fact necessary to make the statements
therein not misleading as of the date made, in either case, which could
reasonably be expected to result in a Material Adverse Effect.
8.1.4 Bankruptcy; Insolvency. Any of Borrower, the
Partners, the Shareholders, Calpine (until Term- Conversion), Phillips, HL&P,
Power Marketer or any other purchaser of capacity or energy from the Project
(so long as Phillips, HL&P, Power Marketer or such other purchaser, as the case
may be, has outstanding or unperformed obligations under the Power Purchase
Documents to which it is party and such party's Bankruptcy Event could
reasonably be expected to have a Material Adverse Effect), the Fuel Supplier or
any Contractor (so long as such Contractor has outstanding or unperformed
obligations under the Construction Contract to which it is a party) shall
become subject to a Bankruptcy Event; provided that, solely with respect to a
Bankruptcy Event affecting any entity other then Borrower, the Partners, the
Shareholders and Calpine, no Event of Default shall occur as a result of such
Bankruptcy Event if Borrower obtains a Replacement Obligor for the affected
party within 90 days thereafter and such Bankruptcy Event has not had and does
not have prior to so obtaining such Replacement Obligor, a Material Adverse
Effect.
8.1.5 Debt Cross Default. Borrower, or, at any
time prior to Term-Conversion, Calpine or any Calpine Affiliate other than a
Calpine Sole Purpose Entity shall default for a period beyond any applicable
grace period (a) in the payment of any principal, interest or other amount due
under any agreement involving the borrowing of money or the advance of credit
and the outstanding amount or amounts payable under all such agreements equals
or exceeds $1,000,000 in the aggregate, or (b) in the payment of any amount or
performance of any obligation due under any guarantee or other agreement if in
either case, pursuant to such default, the holder of the obligation concerned
has the right to accelerate the maturity of an indebtedness evidenced thereby
which equals or exceeds $1,000,000. For purposes of this Section, the term
"Calpine Sole Purpose Entity" shall mean a Calpine Affiliate (i) whose sole
purpose is the ownership and maintenance of a power project (other than the
Project) that has been financed on a non- recourse basis and (ii) that is not
directly connected to the Project or responsible for actions materially and
directly affecting the Project.
8.1.6 ERISA. If Borrower or any member of the
Controlled Group should establish, maintain, contribute to or become obligated
to contribute to any ERISA Plan and (a) a reportable event (as defined in
Section 4043(b) of ERISA) shall have occurred with respect to any ERISA Plan
and, within 30 days after the reporting of such reportable event to Agent by
Borrower (or Agent otherwise obtaining knowledge of such event) and the
furnishing of such information as Agent may reasonably request with respect
thereto, Agent shall have notified Borrower in writing that (i) Agent has made
a determination that, on the basis of such reportable event, there are
reasonable grounds for the termination of such ERISA Plan by the PBGC or for
the appointment by the appropriate United States District Court of a trustee to
administer such ERISA Plan and (ii) as a result thereof, an Event of Default
exists hereunder; or (b) a trustee shall be appointed by a United States
District Court to administer any ERISA Plan; or (c) the PBGC
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shall institute proceedings to terminate any ERISA Plan; or (d) a complete or
partial withdrawal by Borrower or any member of the Controlled Group from any
Multiemployer Plan shall have occurred, or any Multiemployer Plan shall enter
reorganization status, become insolvent, or terminate (or notify Borrower or
any member of the Controlled Group of its intent to terminate) under Section
4041A of ERISA and, within 30 days after the reporting of any such occurrence
to Agent by Borrower (or Agent otherwise obtaining knowledge of such event) and
the furnishing of such information as Agent may reasonably request with respect
thereto, Agent shall have notified Borrower in writing that Agent has made a
determination that, on the basis of such occurrence, an Event of Default exists
hereunder; provided that any of the events described in this Section 8.1.6
shall involve (A) one or more ERISA Plans that are single-employer plans (as
defined in Section 4001(a)(15) of ERISA) and under which the aggregate gross
amount of unfunded benefit liabilities (as defined in Section 4001(a)(16) of
ERISA), including vested unfunded liabilities which arise or might arise as the
result of the termination of such ERISA Plans, and/or (B) one or more
Multiemployer Plans to which the aggregate liabilities of Borrower and all
members of the Controlled Group, shall exceed $500,000.
8.1.7 Breach of Project Documents.
(a) Borrower. Borrower shall be in
breach of any term, condition, provision, covenant, representation, warranty or
obligation, or in default, under a Project Document, and such breach or default
shall not be remediable or, if remediable, shall continue unremedied for a
period of 30 days; provided that, except with respect to a breach or default
under the Phillips Documents, if (i) such breach cannot be cured within such 30
day period, (ii) such breach is susceptible of cure within 90 days, (iii)
Borrower is proceeding with diligence and in good faith to cure such breach,
(iv) the existence of such breach has not had and could not after considering
the nature of the cure, be reasonably expected to give rise to termination by
the counterparty to the Project Document which is subject to breach or to
otherwise have a Material Adverse Effect and (v) Agent shall have received an
officer's certificate signed by a Responsible Officer to the effect of clauses
(i), (ii), (iii) and (iv) above and stating what action Borrower is taking to
cure such breach, then such 30 day cure period shall be extended to such date,
not to exceed a total of 90 days, as shall be necessary for Borrower diligently
to cure such breach.
(b) Third Party. A party other than
Borrower shall be in breach of, or in default under, a Project Document or any
Consent, Pledge and Security Agreement or, Shareholder Pledge and Security
Agreement, or any Equity Document such breach or default shall not be
remediable or, if remediable, shall continue unremedied for a period of 30
days; provided that if (i) such breach cannot be cured within such 30 day
period, (ii) such breach is susceptible of cure within 90 days, (iii) the
breaching party is proceeding with diligence and in good faith to cure such
breach, and (iv) the existence of such breach has not had and could not after
considering the nature of the cure, be reasonably expected to have a Material
Adverse Effect, then such 30 day cure period shall be extended to such date,
not to exceed a total of 90 days, as shall be necessary for such third party
diligently to cure such breach; provided further that, no Event of Default
shall be declared as a result of any such action if Borrower obtains a
Replacement Obligor for the
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affected party within the 90 day cure period referred to in this paragraph (or
within the 30 day cure period, if no extension is given) and such action has
not had and does not have prior to so obtaining such Replacement Obligor a
Material Adverse Effect.
(c) Termination. Any material provision
in any Project Document shall for any reason cease to be valid and binding on
any party thereto (other than Borrower) except upon fulfillment of such party's
obligations thereunder (or any such party shall so state in writing), or shall
be declared null and void, or the validity or enforceability thereof shall be
contested by any party thereto (other than Agent and the Banks) or any
Governmental Authority, or any such party shall deny that it has any liability
or obligation thereunder, except upon fulfillment of its obligations
thereunder; provided that no Event of Default shall occur as a result of such
breach or default if Borrower obtains a Replacement Obligor for the affected
party within 90 days thereafter and, such breach or default has not had and
does not have prior to so obtaining such Replacement Obligor, a Material
Adverse Effect.
8.1.8 Breach of Terms of Agreement.
(a) Borrower shall fail to perform or
observe any of the covenants set forth in Section 5.1, 5.9(a), 5.9(f), 5.11,
5.18, 5.19, 5.22.1 or Article 6 (other than Section 6.7, 6.8, 6.14, 6.15 or
6.20).
(b) Borrower shall fail to perform or
observe any other covenant to be observed or performed by it hereunder or any
other Credit Document not otherwise specifically provided for in Section
8.1.8(a) or elsewhere in this Article 8, and such failure shall continue
unremedied for a period of 30 days after Borrower becomes aware thereof or
receives written notice thereof from Agent provided, however, that, if (i) such
failure cannot be cured within such 30 day period, (ii) such failure is
susceptible of cure, (iii) Borrower is proceeding with diligence and in good
faith to cure such failure, (iv) the existence of such failure has not had and
cannot after considering the nature of the cure be reasonably expected to have
a Material Adverse Effect and (v) Agent shall have received an officer's
certificate signed by a Responsible Officer to the effect of clauses (i), (ii),
(iii) and (iv) above and stating what action Borrower is taking to cure such
failure, then such 30 day cure period shall be extended to such date, not to
exceed a total of 90 days, as shall be necessary for Borrower diligently to
cure such failure.
8.1.9 Term-Conversion. Term-Conversion shall not
have occurred by the Construction Loan Maturity Date.
8.1.10 Conditions to Initial Distributions. Any of
the conditions to the initial distribution set forth in Section 3.5, other than
Section 3.5.7, has not been satisfied or waived prior to the Date Certain.
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8.1.11 Loss of Qualifying Facility Status.
(a) If loss of Qualifying Facility
status could reasonably be expected to have a Material Adverse Effect, (i) FERC
shall have issued an order determining that the Project has ceased to be a
Qualifying Facility or (ii) the Project shall have failed to meet the criteria
for a Qualifying Facility, and, subject to the provisions of Section 8.1.7(a),
shall have failed to obtain a waiver from FERC on account thereof within six
months after the end of any calendar year in which the Borrower knows or should
reasonably have known that it has failed to meet such criteria.
(b) Borrower or any Partner shall lose
the exemption from regulation under PUHCA.
8.1.12 Abandonment.
(a) At any time prior to the
Term-Conversion, Borrower shall announce that it is abandoning the Project or
the Project shall be abandoned or work thereon shall cease for a period of more
than 30 consecutive days for any reason (which period (i) shall be measured
from the first occurrence of a work stoppage and continuing until work of a
substantial nature is resumed and thereafter diligently continued, and (ii)
shall not include delays caused by any event of force majeure or default by a
Major Project Participant (other than Borrower or its Affiliates) under the
Construction Contracts or the Phillips Documents), or the Project shall not be
constructed substantially in accordance with the Plans and Specifications
(except as to changes therein approved by Agent).
(b) At any time following
Term-Conversion, Borrower shall announce that it is abandoning the Project or
the Project shall be abandoned or operation thereof shall cease for a period of
more than thirty (30) consecutive days for any reason (other than force
majeure).
8.1.13 Security. Any of the Collateral Documents,
once executed and delivered, shall, except as the result of the acts or
omissions of Agent or the Banks, fail to provide the Banks the Liens, first
priority security interest, rights, titles, interest, remedies permitted by
law, powers or privileges intended to be created thereby or cease to be in full
force and effect, or the first priority or validity thereof or the
applicability thereof to the Loans, the Notes or any other obligations
purported to be secured or guaranteed thereby or any part thereof shall be
disaffirmed by or on behalf of Borrower.
8.1.14 Loss of Control. The occurrence of any of the following:
(a) At any time prior to
Term-Conversion, without the prior written consent of Agent and the Required
Banks, any Transfer of an ownership interest in Borrower shall occur, other
than a transfer (i) to any Affiliate of Calpine reasonably approved by the
Agent and the Required Banks and (ii) to Phillips pursuant to the Equity Rights
Agreement;
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(b) At any time following
Term-Conversion, without the prior written consent of Agent and the Required
Banks, any Transfer of an ownership interest in Borrower shall occur, other
than a transfer (i) to any Affiliate of Calpine reasonably approved by the
Agent and the Required Banks, (ii) to Phillips pursuant to the Equity Rights
Agreement and (iii) to any Qualified Transferee;
(c) Calpine shall cease to directly or
indirectly (i) own and control at least 50% of the partnership interests in
Borrower or (ii) maintain a controlling managing general partner interest in
Borrower;
(d) CPC shall cease to directly own and
control 100% of the managing general partnership interests in Borrower; or
(e) any Transfer (including the
transfers described in Sections (a), (b), (c) and (d) above) unless (i) no
Event of Default or Inchoate Default shall have occurred and be continuing or
shall occur as a result of any such Transfer; (ii) all Permits and other
certificates, licenses, appraisals or requirements of any Governmental
Authority with respect to such Transfer have been obtained and are in full
force and effect, and such Transfer complies in all material respects with the
terms, conditions and requirements thereof; (iii) such Transfer complies with
the terms and conditions of the Project Documents; (iv) such Transfer complies
with all applicable laws, rules, regulations, ordinances, codes, orders,
decrees or judgments of any Governmental Authority having jurisdiction with
respect thereto, including all federal and state securities laws; (v) all Base
Equity and Additional Borrower Equity required to be deposited under the
Operative Documents has been applied toward Project Costs or payment of Loans
or provision therefor acceptable to Agent has been made; (vi) the intended
transferee has executed and delivered to Agent a pledge and security agreement
in substantially the form of Exhibit D-5 or D-6 to the Credit Agreement; and
(vii) if such intended Transfer is a pledge, hypothecation or other
encumbrance, the intended lienholder shall have executed and delivered a
Subordination Agreement in the form of Exhibit D-8 to the Credit Agreement.
8.1.15 Loss of or Failure to Obtain Applicable
Permits or Applicable Third Party Permits.
(a) Borrower shall fail to obtain any
Permit on or before the date that such Permit becomes an Applicable Permit, or
any Major Project Participant shall fail to obtain any Permit on or before the
date that such Permit becomes an Applicable Third Party Permit, and such
failure could reasonably be expected to have a Material Adverse Effect.
(b) Any Applicable Permit necessary for
operation of the Project shall be materially modified (other than modifications
requested by Borrower and approved in writing in advance of such modification
by Agent acting at the direction of the Majority Banks which approval shall not
be unreasonably withheld), revoked, cancelled or not renewed by the issuing
agency or other Governmental Authority having jurisdiction and within 30 days
thereafter Borrower is not able to demonstrate to the reasonable satisfaction
of the Majority Banks that such
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modification or loss of such Permit reasonably could not be expected to have a
Material Adverse Effect.
(c) Any Third Party Permit necessary for
performance by the applicable Major Project Participant shall be materially
modified, revoked, cancelled or not renewed by the issuing agency or other
Governmental Authority having jurisdiction and within 90 days thereafter
Borrower is not able to (i) demonstrate to the reasonable satisfaction of the
Majority Banks that such modification or loss of such Third Party Permit will
not have a Material Adverse Effect, or (ii) obtain a Replacement Obligor for
such Major Project Participant, where prior to Borrower obtaining such
Replacement Obligor such breach or default has not had and could not reasonably
be expected to have, a Material Adverse Effect.
8.1.16 Loss of Collateral. Any substantial portion
of Borrower's property is damaged, seized or appropriated without fair value
being paid therefor so as to allow replacement of such property and/or
prepayment of Loans and to allow Borrower in Agent's reasonable judgment to
continue satisfying its obligations hereunder and under the other Operative
Documents.
8.1.17 Material Adverse Effect. Except as otherwise
specifically provided in this Article 8, an event causing a Material Adverse
Effect has occurred and is continuing.
8.2 Remedies.
Upon the occurrence and during the continuation of an Event
of Default, Agent and the Banks may, at the election of the Required Banks,
without further notice of default, presentment or demand for payment, protest
or notice of non-payment or dishonor, or other notices or demands of any kind,
all such notices and demands being waived, exercise any or all of the following
rights and remedies, in any combination or order that the Required Banks may
elect, in addition to such other rights or remedies as the Banks may have
hereunder, under the Collateral Documents or at law or in equity:
8.2.1 No Further Loans. Cancel all commitments,
refuse, and Agent and the Banks shall not be obligated, to continue any Loans,
make any additional Loans or make any payments, or permit the making of
payments, from any Account or any Proceeds or other funds held by Agent under
the Credit Documents or on behalf of Borrower:
8.2.2 Cure by Agent. Without any obligation to do
so, make disbursements or Loans to or on behalf of Borrower to cure any Event
of Default hereunder and to cure any default and render any performance under
any Project Documents as the Majority Banks in their sole discretion may
consider necessary or appropriate, whether to preserve and protect the
Collateral or the Banks' interests therein or for any other reason, and all
sums so expended, together with interest on such total amount at the Default
Rate (but in no event shall the rate exceed the maximum lawful rate), shall be
repaid by Borrower to Agent on demand and shall be secured by the Credit
Documents, notwithstanding that such expenditures may, together
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with amounts advanced under this Agreement, exceed the amount of the Total
Construction Loan Commitment.
8.2.3 Acceleration. Declare and make all sums of
accrued and outstanding principal and accrued but unpaid interest remaining
under this Agreement together with all unpaid fees, costs (including
Liquidation Costs and Hedge Breaking Fees) and charges due hereunder or under
any other Credit Document, immediately due and payable, provided that in the
event of an Event of Default occurring under Section 8.1.4 with respect to
Borrower, all such amounts shall become immediately due and payable without
further act of Agent or the Banks.
8.2.4 Cash Collateral. Apply or execute upon any
amounts on deposit in any Account or any Proceeds, Base Equity or any other
moneys of Borrower on deposit with Agent or any Bank in the manner provided in
the Uniform Commercial Code and other relevant statutes and decisions and
interpretations thereunder with respect to cash collateral.
8.2.5 Possession of Project. Enter into possession
of the Project and perform any and all work and labor necessary to complete the
Project substantially according to the Plans and Specifications or to operate
and maintain the Project, and all sums expended by Agent in so doing, together
with interest on such total amount at the Default Rate, shall be repaid by
Borrower to Agent upon demand and shall be secured by the Credit Documents,
notwithstanding that such expenditures may, together with amounts advanced
under this Agreement, exceed the amount of the Total Construction Loan
Commitment.
8.2.6 Remedies Under Credit Documents. Exercise
any and all rights and remedies available to it under any of the Credit
Documents, including judicial or non-judicial foreclosure or public or private
sale of any of the Collateral pursuant to the Collateral Documents.
ARTICLE 9 - SCOPE OF LIABILITY
The Banks shall have no claims with respect to the
transactions contemplated by the Operative Documents against any Partners,
Shareholders or any of their respective Affiliates (other than the Borrower),
shareholders, officers, directors or employees (collectively the "Nonrecourse
Persons"); provided that (a) the foregoing provision of this Article 9 shall
not constitute a waiver, release or discharge of any of the indebtedness, or of
any of the terms, covenants, conditions, or provisions of this Agreement, any
other Security Document or Credit Document and the same shall continue (but
without personal liability to the Nonrecourse Person) until fully paid,
discharged, observed, or performed; (b) the foregoing provision of this Article
9 shall not limit or restrict the right of the Agent and/or the Banks or Hedge
Banks (or any assignee, beneficiary or successor to any of them) to name
Borrower or any other Person as a defendant in any action or suit for a
judicial foreclosure or for the exercise of any other remedy under or with
respect to this Agreement or any other Security Document or Credit Document, or
for injunction or specific performance, so long as no judgment in the nature of
a deficiency judgment shall be enforced against any Nonrecourse Person, except
as set forth in this Article 9, (c) the foregoing provision of this Article 9
shall not in any way limit or restrict any right or
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remedy of Agent and/or the Banks (or any assignee or beneficiary thereof or
successor thereto) with respect to, and each of the Nonrecourse Persons shall
remain fully liable to the extent that it would otherwise be liable for its own
actions with respect to, any fraud (which shall not include innocent or
negligent misrepresentation), willful misrepresentation, or misappropriation of
Project Revenues, Proceeds or any other earnings, revenues, rents, issues,
profits or proceeds from or of the Collateral that should or would have been
paid as provided herein or paid or delivered to Agent or any Bank (or any
assignee or beneficiary thereof or successor thereto) towards any payment
required under this Agreement or any other Credit Document; (d) the foregoing
provision of this Article 9 shall not affect or diminish or constitute a
waiver, release or discharge of any specific written obligation, covenant, or
agreement in respect of the Project made by any of the Nonrecourse Persons or
any security granted by the Nonrecourse Persons in support of the obligations
of such persons under any Equity Document or as security for the obligations of
the Borrower; and (e) nothing contained herein shall limit the liability of (i)
any Person who is a party to any Project Document or has issued any certificate
or other statement in connection therewith with respect to such liability as
may arise by reason of the terms and conditions of such Project Document (but
subject to any limitation of liability in such Project Document), certificate
or statement, or (ii) any Person rendering a legal opinion pursuant to Section
3.1.8, or otherwise, in each case under this clause (e) relating solely to such
liability of such Person as may arise under such referenced agreement,
instrument or opinion. The limitations on recourse set forth in this Article 9
shall survive the termination of this Agreement and the full payment and
performance of the Obligations hereunder and under the other Operative
Documents.
ARTICLE 10 - THE AGENT; SUBSTITUTION
10.1 Appointment, Powers and Immunities.
10.1.1 Each Bank hereby appoints and authorizes
Agent to act as its agent hereunder and under the other Credit Documents with
such powers as are expressly delegated to Agent by the terms of this Agreement
and the other Credit Documents, together with such other powers as are
reasonably incidental thereto. Agent shall not have any duties or
responsibilities except those expressly set forth in this Agreement or in any
other Credit Document, or be a trustee for any Bank. Notwithstanding anything
to the contrary contained herein Agent shall not be required to take any action
which is contrary to this Agreement or any other Credit Documents or any Legal
Requirement or exposes Agent to any liability. Each of Agent, the Banks and
any of their respective Affiliates shall not be responsible to any other Bank
for any recitals, statements, representations or warranties made by Borrower,
its Affiliates or Partners contained in this Agreement or in any certificate or
other document referred to or provided for in, or received by Agent, or any
Bank under this Agreement, for the value, validity, effectiveness, genuineness,
enforceability or sufficiency of this Agreement, the Notes or any other
document referred to or provided for herein or for any failure by Borrower, its
Affiliates, its Partners or the Shareholders to perform their respective
obligations hereunder or thereunder. Agent may employ agents and
attorneys-in-fact and shall not be responsible for the negligence or misconduct
of any such agents or attorneys-in-fact selected by it with reasonable care.
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10.1.2 Agent and its respective directors, officers,
employees or agents shall not be responsible for any action taken or omitted to
be taken by it or them hereunder or under any other Credit Document or in
connection herewith or therewith, except for its or their own gross negligence
or willful misconduct. Without limiting the generality of the foregoing, Agent
(a) may treat the payee of any Note as the holder thereof until Agent receives
written notice of the assignment or transfer thereof signed by such payee and
in form satisfactory to Agent; (b) may consult with legal counsel, independent
public accountants and other experts selected by it and shall not be liable for
any action taken or omitted to be taken in good faith by them in accordance
with the advice of such counsel, accountants or experts; (c) makes no warranty
or representation to any Bank for any statements, warranties or representations
made in or in connection with any Project Document or Credit Document; (d)
shall not have any duty to ascertain or to inquire as to the performance or
observance of any of the terms, covenants or conditions of any Operative
Document on the part of any party thereto or to inspect the property (including
the books and records) of Borrower or any other Person; and (e) shall not be
responsible to any Bank for the due execution, legality, validity,
enforceability, genuineness, sufficiency or value of any Operative Document or
any other instrument or document furnished pursuant hereto. Except as
otherwise provided under this Agreement, Agent shall take such action with
respect to the Credit Documents as shall be directed by the Majority Banks.
10.2 Reliance by Agent. Agent shall be entitled to rely
upon any certificate, notice or other document (including any cable, telegram,
telecopy or telex) believed by it to be genuine and correct and to have been
signed or sent by or on behalf of the proper Person or Persons, and upon advice
and statements of legal counsel, independent accountants and other experts
selected by Agent. As to any other matters not expressly provided for by this
Agreement, Agent shall not be required to take any action or exercise any
discretion, but shall be required to act or to refrain from acting upon
instructions of the Majority Banks or, where expressly provided, the Required
Banks (except that Agent shall not be required to take any action which exposes
Agent to personal liability or which is contrary to this Agreement, any other
Credit Document or any Legal Requirement) and shall in all cases be fully
protected in acting, or in refraining from acting, hereunder or under any other
Credit Document in accordance with the instructions of the Majority Banks (or,
where so expressly stated, the Required Banks), and such instructions of the
Majority Banks (or Required Banks, where applicable) and any action taken or
failure to act pursuant thereto shall be binding on all of the Banks.
10.3 Non-Reliance. Each Bank represents that it has,
independently and without reliance on Agent or any other Bank, and based on
such documents and information as it has deemed appropriate, made its own
appraisal of the financial condition and affairs of Borrower and decision to
enter into this Agreement and agrees that it will, independently and without
reliance upon Agent, or any other Bank, and based on such documents and
information as it shall deem appropriate at the time, continue to make its own
appraisals and decisions in taking or not taking action under this Agreement.
Each of Agent and any Bank shall not be required to keep informed as to the
performance or observance by Borrower, its Affiliates or Partners under this
Agreement or any other document referred to or provided for herein or to make
inquiry of, or to inspect the properties or books of Borrower, its Affiliates
or Partners.
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10.4 Defaults. Agent shall not be deemed to have
knowledge or notice of the occurrence of any Inchoate Default or Event of
Default unless Agent has received a notice from a Bank or Borrower, referring
to this Agreement, describing such Inchoate Default or Event of Default and
indicating that such notice is a notice of default. If Agent receives such a
notice of the occurrence of an Inchoate Default or Event of Default, Agent
shall give notice thereof to the Banks. Agent shall take such action with
respect to such Inchoate Default or Event of Default as is provided in Article
8 or if not provided for in Article 8, as Agent shall be reasonably directed by
the Majority Banks; provided, however, unless and until Agent shall have
received such directions, Agent may (but shall not be obligated to) take such
action, or refrain from taking such action, with respect to such Inchoate
Default or Event of Default as it shall deem advisable in the best interest of
the Banks.
10.5 Indemnification. Without limiting the Obligations of
Borrower hereunder, each Bank agrees to indemnify Agent, ratably in accordance
with their Proportionate Shares for any and all liabilities, obligations,
losses, damages, penalties, actions, judgments, suits, costs, expenses or
disbursements of any kind or nature whatsoever which may at any time be imposed
on, incurred by or asserted against Agent in any way relating to or arising out
of this Agreement or any documents contemplated by or referred to herein or
therein or the transactions contemplated hereby or thereby or the enforcement
of any of the terms hereof or thereof or of any such other documents; provided,
however, that no Bank shall be liable for any of the foregoing to the extent
they arise from Agent's gross negligence or willful misconduct. Agent shall be
fully justified in refusing to take or to continue to take any action hereunder
unless it shall first be indemnified to its satisfaction by the Banks against
any and all liability and expense which may be incurred by it by reason of
taking or continuing to take any such action. Without limitation of the
foregoing, each Bank agrees to reimburse Agent promptly upon demand for its
ratable share of any out-of-pocket expenses (including counsel fees) incurred
by Agent in connection with the preparation, execution, administration or
enforcement of, or legal advice in respect of rights or responsibilities under,
the Operative Documents, to the extent that Agent is not reimbursed for such
expenses by Borrower.
10.6 Successor Agent. Agent acknowledges that its current
intention is to remain Agent hereunder. Nevertheless, Agent may resign at any
time by giving written notice thereof to the Banks and Borrower. Agent may be
removed involuntarily only for a material breach of its duties and obligations
hereunder or under the other Credit Documents or for gross negligence or
willful misconduct in connection with the performance of its duties hereunder
or under the other Credit Documents and then only upon the affirmative vote of
the Majority Banks (excluding Agent from such vote and Agent's Proportionate
Share of the Commitment from the amounts used to determine the portion of the
Commitment necessary to constitute the required Proportionate Share of the
remaining Banks). Upon any such resignation or removal, the Majority Banks
shall have the right, with the consent of Borrower (such consent not to be
unreasonably withheld or delayed) to appoint a successor Agent. If no
successor Agent shall have been so appointed by the Majority Banks, and shall
have accepted such appointment, within 30 days after the retiring Agent's
giving of notice of resignation or the Banks' removal of the retiring Agent,
the retiring Agent may, on behalf of the Banks, with the consent of Borrower
(such consent not to be
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unreasonably withheld or delayed), appoint a successor Agent, which shall be a
Bank, if any Bank shall be willing to serve, and otherwise shall be a
commercial bank having a combined capital and surplus of at least $500,000,000.
Upon the acceptance of any appointment as Agent under the Operative Documents
by a successor Agent, such successor Agent shall thereupon succeed to and
become vested with all the rights, powers, privileges and duties of the
retiring Agent, and the retiring Agent shall be discharged from its duties and
obligations as Agent only under the Credit Documents. After any retiring
Agent's resignation or removal hereunder as Agent, the provisions of this
Article 10 shall inure to its benefit as to any actions taken or omitted to be
taken by it while it was Agent under the Operative Documents.
10.7 Authorization. Agent is hereby authorized by the
Banks to execute, deliver and perform each of the Credit Documents to which
Agent is or is intended to be a party and each Bank agrees to be bound by all
of the agreements of Agent contained in the Credit Documents. Agent is further
authorized by the Banks to release liens on property that Borrower is permitted
to sell or transfer pursuant to the terms of this Agreement, the other Credit
Documents or the Operative Documents, and to enter into agreements supplemental
hereto for the purpose of curing any formal defect, inconsistency, omission or
ambiguity in this Agreement or any Credit Document to which it is a party.
10.8 Agent. With respect to its Commitment, the Loans
made by it and any Note issued to it, Agent shall have the same rights and
powers under the Operative Documents as any other Bank and may exercise the
same as though it were not Agent. The term "Bank" or "Banks" shall, unless
otherwise expressly indicated, include Agent in its individual capacity. Agent
and its Affiliates may accept deposits from, lend money to, act as trustee
under indentures of, and generally engage in any kind of business with Borrower
or any other Person, without any duty to account therefor to the Banks.
10.9 Amendments; Waivers. Subject to the provisions of
this Section 10.9, unless otherwise specified in this Agreement or another
Credit Document, the Required Banks (or Agent with the consent in writing of
the Required Banks) and Borrower may enter into agreements supplemental hereto
for the purpose of adding, modifying or waiving any provisions to the Credit
Documents or changing in any manner the rights of the Banks or Borrower
hereunder or waiving any Inchoate Default or Event of Default; provided,
however, that no such supplemental agreement shall, without the consent of all
of the Banks:
10.9.1 Extend the maturity of any Loan or any of the
Notes or reduce the principal amount thereof, or reduce the rate or change the
time of payment of interest due on any Loan or any Notes; or
10.9.2 Extend the Construction Loan Maturity Date;
or
10.9.3 Modify Section 2.1.1(d), 2.5, 2.6, 2.7, 5.1,
5.18, 6.17, 6.22, 7.1 through 7.18, 8.1.13, 10.1, 10.13 or 10.14; or
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10.9.4 Reduce the amount or extend the payment date
for any amount due under Article 2, whether principal, interest, fees or other
amounts; or
10.9.5 Increase the amount of the Commitment of any
Bank hereunder; or
10.9.6 Reduce or change the time of payment of any
fee due or payable hereunder; or
10.9.7 Reduce the percentage specified in the
definition of Majority Banks or Required Banks; or
10.9.8 Permit Borrower to assign its rights under
this Agreement except as provided in Section 6.17, or permit a Transfer except
as provided in Section 8.1.14, or
10.9.9 Amend this Section 10.9; or
10.9.10 Release any Collateral from the Lien of any
of the Collateral Documents or allow release of any funds from any Account
otherwise than in accordance with the terms hereof.
No amendment of any provision of this Agreement relating to
Agent shall be effective without the written consent of Agent.
10.10 Withholding Tax.
10.10.1 Agent may withhold from any interest payment
to any Bank an amount equivalent to any applicable withholding tax. If the
forms or other documentation required by Section 2.5 are not delivered to
Agent, then Agent may withhold from any interest payment to any Bank not
providing such forms or other documentation, an amount equivalent to the
applicable withholding tax.
10.10.2 If the Internal Revenue Service or any
authority of the United States or other jurisdiction asserts a claim that Agent
did not properly withhold tax from amounts paid to or for the account of any
Bank (because the appropriate form was not delivered, was not properly
executed, or because such Bank failed to notify Agent of a change in
circumstances which rendered the exemption from, or reduction of, withholding
tax ineffective, or for any other reason) such Bank shall indemnify Agent fully
for all amounts paid, directly or indirectly, by Agent as tax or otherwise,
including penalties and interest, together with all expenses incurred,
including legal expenses, allocated staff costs, and any out of pocket
expenses.
10.10.3 If any Bank sells, assigns, grants
participation in, or otherwise transfers its rights under this Agreement, the
purchaser, assignee, participant or transferee, as applicable, shall comply and
be bound by the terms of Sections 2.4.7, 10.10.1 and 10.10.2 as though it were
such Bank.
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10.11 General Provisions as to Payments. Agent shall
promptly distribute to each Bank, subject to the terms of the assignment and
assumption agreement between Agent and such Bank, its pro rata share of each
payment of principal and interest payable to the Banks on the Loans and of fees
hereunder received by Agent for the account of the Banks and of any other
amounts owing under the Loans. The payments made for the account of each Bank
shall be made, and distributed to it, for the account of (a) its domestic
lending office in the case of payments of principal of, and interest on, its
Base Rate Loans, (b) its domestic or foreign lending office, as each Bank may
designate in writing to Agent, in the case of LIBOR Loans, and (c) its domestic
lending office, or such other lending office as it may designate for the
purpose from time to time, in the case of payments of fees and other amounts
payable hereunder. Banks shall have the right to alter designated domestic
lending offices upon notice to Agent and Borrower.
10.12 Substitution of Bank. Should any Bank fail to make a
Loan in violation of its obligations under this Agreement (a "Non-Advancing
Bank"), Agent shall (a) in its sole discretion fund the Loan on behalf of the
Non-Advancing Bank or (b) cooperate with Borrower or any other Bank to find
another Person that shall be acceptable to Agent and that shall be willing to
assume the Non-Advancing Bank's obligations under this Agreement (including the
obligation to make the Loan which the Non-Advancing Bank failed to make but
without assuming any liability for damages for failing to have made such Loan
or any previously required Loan). Subject to the provisions of the next
following sentence, such Person shall be substituted for the Non-Advancing Bank
hereunder upon execution and delivery to Agent of an agreement acceptable to
Agent by such Person assuming the Non-Advancing Bank's obligations under this
Agreement, and all interest and fees which would otherwise have been payable to
the Non-Advancing Bank shall thereafter be payable to such Person. Nothing in
(and no action taken pursuant to) this Section 10.12 shall relieve the
Non-Advancing Bank from any liability it might have to Borrower or to the other
Banks as a result of its failure to make any Loan.
10.13 Participation. Nothing herein provided shall prevent
any Bank from selling a participation in its Commitment (and Loans made
thereunder) in an aggregate amount of at least $5,000,000 with respect to any
participant; provided that (a) no such sale of a participation shall alter such
Bank's or the Borrower's obligations hereunder, (b) any agreement pursuant to
which any Bank may grant a participation in its rights with respect to its
Commitment (and Loans) shall provide that, with respect to such Commitment (and
Loans), subject to the following proviso, such Bank shall retain the sole right
and responsibility to exercise the rights of such Bank, and enforce the
obligations of Borrower relating to such Commitment (and Loans), including the
right to approve any amendment, modification or waiver of any provision of this
Agreement or any other Bank Document and the right to take action to have the
Notes declared due and payable pursuant to Article 8; provided, however, that
such agreement may provide that the participant may have rights to approve or
disapprove decreases in interest rates or fees, lengthening of maturity of any
Loans, or release of any material Collateral. No recipient of a participation
in any Commitment or Loans of any Bank shall have any rights under this
Agreement or shall be entitled to any reimbursement for Taxes, Other Taxes
increased costs or reserve requirements under Sections 2.4 or 2.6 or any other
indemnity or payment rights against the Borrower (but shall be permitted to
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receive from the Bank granting such participation a proportionate amount which
would have been payable to the Bank from whom such Person acquired its
participation).
10.14 Transfer of Commitment. Notwithstanding anything
else herein to the contrary, any Bank, after receiving Agent's prior written
consent, and after reasonable notice to and consultation with Borrower, may
from time to time, at its option, sell, assign, transfer, negotiate or
otherwise dispose of a portion of its Commitment (and Loans made thereunder)
(including the Bank's interest in this Agreement and the other Credit
Documents) to any bank or other lending institution which in such assigning
Bank's judgment is reasonably capable of performing the obligations of a Bank
hereunder and reasonably experienced in project financing; provided, however,
that no Bank (including any assignee of any Bank) may assign any portion of its
Commitment (including Loans) of less than $5,000,000 (unless to another Bank)
or which leaves the assigning Bank with a Commitment (including Loans) of less
than $5,000,000 after giving effect to such assignment and all previous
assignments (except that a Bank may be left with no Commitment and Loans if it
assigns its entire Commitment and Loans). In the event of any such assignment,
(a) the assigning Bank's Proportionate Share shall be reduced by the amount of
the Proportionate Share assigned to the new lender, (b) the parties to such
assignment shall execute and deliver an appropriate agreement evidencing such
sale, assignment, transfer or other disposition, (c) at the assigning Bank's
option, Borrower shall execute and deliver to such new lender new Notes in the
forms attached hereto as Exhibits B-1 or Exhibit B-2, as appropriate, in a
principal amount equal to such new lender's Commitment, and Borrower shall
execute and exchange with the assigning Bank a replacement note for any Note in
an amount equal to the Commitment retained by the Bank, if any and (d) Agent
may amend Exhibit H attached hereto to reflect the Proportionate Shares of the
Banks following such assignment. Thereafter, such new lender shall be deemed
to be a Bank and shall have all of the rights and duties of a Bank (except as
otherwise provided in this Article 10), in accordance with its Proportionate
Share, under each of the Credit Documents.
10.15 Laws. Notwithstanding the foregoing provisions of
this Article 10, no sale, assignment, transfer, negotiation or other
disposition of the interests of any Bank hereunder or under the other Credit
Documents shall be allowed if it would require registration under the federal
Securities Act of 1933, as then amended, any other federal securities laws or
regulations or the securities laws or regulations of any applicable
jurisdiction. Borrower shall, from time to time at the request and expense of
Agent, execute and deliver to Agent, or to such party or parties as Agent may
designate, any and all further instruments as may in the opinion of Agent be
reasonably necessary or advisable to give full force and effect to such
disposition.
10.16 Assignability to Federal Reserve Bank.
Notwithstanding any other provision contained in this Agreement or any other
Credit Document to the contrary, any Bank may assign all or any portion of the
Loans or Notes held by it to any Federal Reserve Bank or the United States
Treasury as collateral security pursuant to Regulation A of the Board of
Governors of the Federal Reserve System and any Operating Circular issued by
such Federal Reserve Bank, provided that any payment in respect of such
assigned Loans or Notes made by Borrower to or for the account of the assigning
and/or pledging Bank in accordance with the terms of this
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Agreement shall satisfy Borrower's obligations hereunder in respect of such
assigned Loans or Notes to the extent of such payment. No such assignment
shall release the assigning Bank from its obligations hereunder.
ARTICLE 11 - INDEPENDENT CONSULTANTS
11.1 Removal and Fees. Agent, in its reasonable
discretion, may remove from time to time, any one or more of the Independent
Consultants and, after consulting with Borrower as to an appropriate Person,
appoint replacements as Agent may choose. Notice of any replacement
Independent Consultant shall be given by Agent to Borrower, the Banks and to
the Independent Consultant being replaced. All reasonable fees and expenses of
the Independent Consultants (whether the original ones or replacements) shall
be paid by Borrower.
11.2 Duties. Each Independent Consultant shall be
contractually obligated to Agent to carry out the activities required of it in
this Agreement and as otherwise requested by Agent and shall be responsible
solely to Agent. Borrower acknowledges that it will not have any cause of
action or claim against any Independent Consultant resulting from any decision
made or not made, any action taken or not taken or any advice given by such
Independent Consultant in the due performance in good faith of its duties to
Agent, except to the extent arising from such Independent Consultant's gross
negligence or willful misconduct.
11.3 Independent Consultants' Certificates.
11.3.1 Until the receipt by Agent of certificates
satisfactory to Agent from each Independent Consultant whom Agent considers
necessary or appropriate certifying Completion, Borrower shall provide such
documents and information to the Independent Consultants as any of the
Independent Consultants may reasonably consider necessary in order for the
Independent Consultants to deliver to Agent the following certificates:
(a) certificates of the Insurance
Consultant, Independent Engineer, Fuel Consultant and Power Marketing
Consultant delivered on and dated as of the Closing Date as described in
Sections 3.1.9, 3.1.11, 3.1.12, 3.1.13 and 3.1.14, respectively, and containing
the matters set out therein;
(b) after the Closing Date, all
certificates to be delivered pursuant to Section 3.2.4 or, if no Loan has taken
place in any month, certificates delivered at the end of the month as to the
matters required by Exhibit C-5; and
(c) monthly after the Closing Date, a
full report and status of the progress of the Project to that date, a complete
assessment of Project Costs to Final Completion and such other information and
certification as Agent may reasonably require from time to time.
11.3.2 Following Completion, Borrower shall provide
such documents and information to the Independent Consultants as they may
reasonably consider necessary in order
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for the Independent Consultants to deliver annually to Agent a certificate
setting forth a full report on the status of the Project and such other
information and certification as Agent may reasonably require from time to
time.
11.4 Certification of Dates. Agent will request that the
Independent Consultants act diligently in the issuance of all certificates
required to be delivered by the Independent Consultants hereunder, if their
issuance is appropriate. Borrower shall provide the Independent Consultants
with reasonable notice of the expected occurrence of any such dates or events.
ARTICLE 12 - MISCELLANEOUS
12.1 Addresses.
Any communications between the parties hereto or notices
provided herein to be given may be given to the following addresses:
<TABLE>
<S> <C>
If to Agent: ING (U.S.) Capital Corporation
135 East 57th Street
8th Floor
New York, New York 10022
Attn: Manager, Project Finance
Telephone No.: (212) 350-7700
Telecopy No.: (212) 486-4636
If to Borrower: Pasadena Cogeneration L.P.
50 West San Fernando Street
San Jose, California 95113
Attn: Asset Manager and General Counsel
Telephone No.: (408) 995-5115
Telecopy No.: (408) 995-0505
</TABLE>
All notices or other communications required or permitted to
be given hereunder shall be in writing and shall be considered as properly
given (a) if delivered in person, (b) if sent by overnight delivery service
(including Federal Express, ETA, Emery, DHL, AirBorne and other similar
overnight delivery services), (c) in the event overnight delivery services are
not readily available, if mailed by first class United States Mail, postage
prepaid, registered or certified with return receipt requested or (d) if sent
by prepaid telegram, or by telecopy confirmed by telephone. Notice so given
shall be effective upon receipt by the addressee, except that communication or
notice so transmitted by telecopy or other direct written electronic means
shall be deemed to have been validly and effectively given on the day (if a
Banking Day and, if not, on the next following Banking Day) on which it is
transmitted if transmitted before 4:00 p.m., recipient's time, and if
transmitted after that time, on the next following Banking Day; provided,
however, that if any notice is tendered to an addressee and the delivery
thereof is refused by such addressee, such notice shall be effective upon such
tender. Any party shall have the right to change its address
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for notice hereunder to any other location within the continental United States
by giving of 30 days' notice to the other parties in the manner set forth
hereinabove.
12.2 Additional Security; Right to Set-Off. Any deposits
or other sums at any time credited or due from Banks and any Project Revenues,
securities or other property of Borrower in the possession of Agent may at all
times be treated as collateral security for the payment of the Loans and the
Notes and all other obligations of Borrower to Banks under this Agreement and
the other Credit Documents, and Borrower hereby pledges to Agent for the
benefit of the Banks and grants Agent a security interest in and to all such
deposits, sums, securities or other property. Regardless of the adequacy of
any other collateral, Agent and only Agent, may execute or realize on the
Banks' security interest in any such deposits or other sums credited by or due
from Banks to Borrower, may apply any such deposits or other sums to or set
them off against Borrower's obligations to Banks under the Notes and this
Agreement at any time after the occurrence and during the continuance of any
Event of Default.
12.3 Delay and Waiver. No delay or omission to exercise
any right, power or remedy accruing to the Banks upon the occurrence of any
Event of Default or Inchoate Default or any breach or default of Borrower under
this Agreement or any other Credit Document shall impair any such right, power
or remedy of the Banks, nor shall it be construed to be a waiver of any such
breach or default, or an acquiescence therein, or of or in any similar breach
or default thereafter occurring, nor shall any waiver of any single Event of
Default, Inchoate Default or other breach or default be deemed a waiver of any
other Event of Default, Inchoate Default or other breach or default theretofore
or thereafter occurring. Any waiver, permit, consent or approval of any kind
or character on the part of Agent and/or the Banks of any Event of Default,
Inchoate Default or other breach or default under this Agreement or any other
Credit Document, or any waiver on the part of Agent and/or the Banks of any
provision or condition of this Agreement or any other Credit Document, must be
in writing and shall be effective only to the extent in such writing
specifically set forth. All remedies, either under this Agreement or any other
Credit Document or by law or otherwise afforded to Agent, LC Bank and the
Banks, shall be cumulative and not alternative.
12.4 Costs, Expenses and Attorneys' Fees; Syndication.
12.4.1 Borrower will pay to Agent all of its
reasonable costs and expenses in connection with the preparation, negotiation,
closing and administering this Agreement and the documents contemplated hereby
and any participation or syndication of the Loans, including the reasonable
fees, expenses and disbursements of Latham & Watkins and other attorneys
retained by Agent in connection with the preparation of such documents and any
amendments hereof or thereof, or the preparation, negotiation, closing,
administration, enforcement, participation or syndication of the Loans or this
Agreement, the reasonable fees, expenses and disbursements of the Independent
Consultants and any other engineering, insurance and construction consultants
to Agent incurred in connection with this Agreement or the Loans subsequent to
the Closing Date, and the travel and out-of-pocket costs incurred by Agent
following the Closing Date, and Borrower further agrees to pay Agent the
out-of-pocket costs and travel costs incurred by Agent
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in connection with syndication of the Loans; provided, however, Borrower shall
not be required to pay advertising costs of any of the Banks or the fees of the
Banks' (other than Agent's) attorneys. Borrower will reimburse Agent for all
costs and expenses, including reasonable attorneys' fees, expended or incurred
by Agent in enforcing this Agreement or the other Credit Documents in
connection with an Event of Default or Inchoate Default, in actions for
declaratory relief in any way related to this Agreement or in collecting any
sum which becomes due Agent on the Notes or under the Credit Documents.
12.4.2 In connection with syndication of the Loans
and Commitments, an information package containing certain relevant information
concerning Borrower, the Project and the other Project participants will be
provided to potential Banks and participants. Borrower agrees to cooperate and
to cause the Partners and the Shareholders to cooperate in the syndication of
the Loans and Commitments in all respects reasonably requested by Agent,
including participation in bank meetings held in connection with such
syndication, and to provide, for inclusion in such package, all information
which Agent may request from it or which Agent or Borrower may consider
material to a lender or participant, or necessary or appropriate for accurate
and complete disclosure. Upon request of Agent, Borrower shall represent to
Agent, and indemnify Agent for claims relating to, the accuracy and
completeness of such disclosure, upon terms acceptable to Agent.
12.5 Entire Agreement. This Agreement and any agreement,
document or instrument attached hereto or referred to herein integrate all the
terms and conditions mentioned herein or incidental hereto and supersede all
oral negotiations and prior writings in respect to the subject matter hereof.
In the event of any conflict between the terms, conditions and provisions of
this Agreement and any such agreement, document or instrument, the terms,
conditions and provisions of this Agreement shall prevail. This Agreement and
the other Credit Documents may only be amended or modified by an instrument in
writing signed by Borrower, Agent and any other parties to such agreements.
12.6 Governing Law. This Agreement, and any instrument or
agreement required hereunder (to the extent not otherwise expressly provided
for therein), shall be governed by, and construed under, the laws of the State
of New York, without reference to conflicts of laws (other than Section 5-1401
of the New York General Obligations Law).
12.7 Severability. In case any one or more of the
provisions contained in this Agreement should be invalid, illegal or
unenforceable in any respect, the validity, legality and enforceability of the
remaining provisions shall not in any way be affected or impaired thereby.
12.8 Headings. Paragraph headings have been inserted in
this Agreement as a matter of convenience for reference only and it is agreed
that such paragraph headings are not a part of this Agreement and shall not be
used in the interpretation of any provision of this Agreement.
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12.9 Accounting Terms. All accounting terms not
specifically defined herein shall be construed in accordance with GAAP and
practices consistent with those applied in the preparation of the financial
statements submitted by Borrower to Agent, and all financial data submitted
pursuant to this Agreement shall be prepared in accordance with such principles
and practices.
12.10 Additional Financing. The parties hereto acknowledge
that the Banks have made no agreement or commitment to provide any financing
except as set forth herein.
12.11 No Partnership, Etc. The Banks and Borrower intend
that the relationship between them shall be solely that of creditor and debtor.
Nothing contained in this Agreement, the Notes or in any of the other Credit
Documents shall be deemed or construed to create a partnership,
tenancy-in-common, joint tenancy, joint venture or co-ownership by or between
the Banks and Borrower or any other Person. The Banks shall not be in any way
responsible or liable for the debts, losses, obligations or duties of Borrower
or any other Person with respect to the Project or otherwise. All obligations
to pay real property or other taxes, assessments, insurance premiums, and all
other fees and charges arising from the ownership, operation or occupancy of
the Project and to perform all obligations and other agreements and contracts
relating to the Project shall be the sole responsibility of Borrower.
12.12 Deed of Trust/Collateral Documents. The Loans are
secured in part by the Deed of Trust encumbering certain properties in the
State of Texas. Reference is hereby made to the Deed of Trust and the other
Collateral Documents for the provisions, among others, relating to the nature
and extent of the security provided thereunder, the rights, duties and
obligations of Borrower and the rights of Agent and the Banks with respect to
such security.
12.13 Limitation on Liability. No claim shall be made by
Borrower, any Partner or any of their Affiliates against the Banks or any of
their Affiliates, directors, employees, attorneys or agents for any special,
indirect, consequential or punitive damages in respect of any breach or
wrongful conduct (whether or not the claim therefor is based on contract, tort
or duty imposed by law), in connection with, arising out of or in any way
related to the transactions contemplated by this Agreement or the other
Operative Documents or any act or omission or event occurring in connection
therewith except to the extent that any such claims are caused by the gross
negligence or willful misconduct of the Banks; and Borrower hereby waives,
releases and agrees not to sue upon any such claim for any such damages,
whether or not accrued and whether or not known or suspected to exist in its
favor.
12.14 Waiver of Jury Trial. THE BANKS AND BORROWER HEREBY
KNOWINGLY, VOLUNTARILY, AND INTENTIONALLY WAIVE ANY RIGHTS THEY MAY HAVE TO A
TRIAL BY JURY IN RESPECT OF ANY LITIGATION BASED HEREON, OR ARISING OUT OF,
UNDER, OR IN CONNECTION WITH, THIS AGREEMENT OR ANY OTHER CREDIT DOCUMENT, OR
ANY COURSE OR CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR
WRITTEN), OR ACTIONS OF THE
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BANKS OR BORROWER. THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE BANKS TO
ENTER INTO THIS AGREEMENT.
12.15 Consent to Jurisdiction. The Banks and Borrower
agree that any legal action or proceeding by or against Borrower or with
respect to or arising out of this Agreement, the Notes, or any other Credit
Document may be brought in or removed to the courts of the State of New York,
in and for the County of New York, or of the United States of America for the
Southern District of New York, as Agent may elect. By execution and delivery
of the Agreement, the Banks and Borrower accept, for themselves and in respect
of their property, generally and unconditionally, the jurisdiction of the
aforesaid courts. The Banks and Borrower irrevocably consent to the service of
process out of any of the aforementioned courts in any manner permitted by law.
Nothing herein shall affect the right of Agent to bring legal action or
proceedings in any other competent jurisdiction, including judicial or
non-judicial foreclosure of the Deed of Trust. Notwithstanding the foregoing,
service of process shall not be deemed served or mailed to Agent or the Banks
until a copy of all matters to be served have be mailed to Latham & Watkins,
701 B Street, Suite 2100, San Diego, California 92101, Attn: Andrew D. Singer
or such other Person as Agent or the Banks may hereafter designate by notice
given pursuant to Section 12.1. The Banks and Borrower further agree that the
aforesaid courts of the State of New York and of the United States of America
shall have exclusive jurisdiction with respect to any claim or counterclaim of
Borrower based upon the assertion that the rate of interest charged by the
Banks on or under this Agreement, the Loans and/or the other Credit Documents
is usurious. The Banks and Borrower hereby waive any right to stay or dismiss
any action or proceeding under or in connection with any or all of the Project,
this Agreement or any other Credit Document brought before the foregoing courts
on the basis of forum non-conveniens.
12.16 Usury. Nothing contained in this Agreement or the
Notes shall be deemed to require the payment of interest or other charges by
Borrower or any other Person in excess of the amount which the holders of the
Notes may lawfully charge under any applicable usury laws. In the event that
the holders of the Notes shall collect moneys which are deemed to constitute
interest which would increase the effective interest rate to a rate in excess
of that permitted to be charged by applicable law, all such sums deemed to
constitute interest in excess of the legal rate shall, upon such determination,
at the option of the holder of the Notes, be returned to Borrower or credited
against the principal balance of the Notes then outstanding.
12.17 Knowledge and Attribution. References in this
Agreement and the other Credit Documents to the "knowledge," "best knowledge"
or facts and circumstances "known to" Borrower, and all like references, mean
facts or circumstances of which a Responsible Officer of Borrower or a Partner
has actual knowledge.
12.18 Successors and Assigns. The provisions of this
Agreement shall be binding upon and inure to the benefit of the parties hereto
and their respective successors and assigns. Borrower may not assign or
otherwise transfer any of its rights under this Agreement except as provided in
Section 6.17, and the Banks may not assign or otherwise transfer any of their
rights under this Agreement except as provided in Article 10.
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12.19 Counterparts. This Agreement may be executed in one
or more duplicate counterparts and when signed by all of the parties listed
below shall constitute a single binding agreement.
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IN WITNESS WHEREOF, the parties have caused this Credit
Agreement to be duly executed by their officers or partners thereunto duly
authorized as of the day and year first above written.
<TABLE>
<S> <C>
PASADENA COGENERATION L.P.,
a Delaware limited partnership
By: Calpine Pasadena Cogeneration, Inc.,
a Delaware corporation,
its General Partner
By:
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Name:
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Title:
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ING (U.S.) CAPITAL CORPORATION,
as Agent
By:
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Name:
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Title:
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By:
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Name:
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Title:
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</TABLE>
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<TABLE>
<S> <C>
ING (U.S.) CAPITAL CORPORATION,
as Bank
By:
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Name:
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Title:
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By:
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Name:
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Title:
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</TABLE>
S-2
<PAGE> 1
EXHIBIT 10.3.11
AMENDED AND RESTATED
ENERGY SALES AGREEMENT
THIS AMENDED AND RESTATED ENERGY SALES AGREEMENT is entered into as of
December 16, 1996 by and between Phillips Petroleum Company, a Delaware
corporation, and Pasadena Cogeneration L.P., a Delaware limited partnership.
RECITALS
A. Phillips owns and operates HCC, which utilizes steam and electrical energy
for industrial purposes. The Partnership will construct, own and operate
the Project and intends to sell steam and electrical energy generated at
the Project to Phillips, and electrical energy to Third-Party Purchasers.
The Partnership intends that the Project will be certified as a
"Qualifying Cogeneration Facility" under the provisions of PURPA.
B. The Parties have previously entered into that certain Energy Sales
Agreement dated as of August 30, 1996 setting forth their respective
rights and obligations in connection with the operation of the Project,
and the purchase by Phillips and the sale by the Partnership of Electrical
Energy and Steam.
C. The Parties desire to modify the Energy Sales Agreement dated as of August
30, 1996 in certain respects to modify certain of their respective rights
and obligations in connection with the operation of the Project, and the
purchase by Phillips and the sale by the Partnership of Electrical Energy
and Steam.
D. The Parties therefore desire to amend and restate the Energy Sales
Agreement dated as of August 30, 1996 in its entirety and to enter into
this Agreement, which shall supersede the Energy Sales Agreement dated as
of August 30, 1996 in its entirety, effective as of December 16, 1996, to
set forth their respective rights and obligations in connection with the
operation of the Project, and the purchase by Phillips and the sale by the
Partnership of Electrical Energy and Steam.
NOW, THEREFORE, in consideration of the mutual promises and agreements set
forth herein, the Parties, intending to be legally bound, hereby agree as
follows:
1. DEFINITIONS AND INTERPRETATION
1.1 DEFINITIONS. Capitalized terms used in this Agreement without
other definition shall have the meanings specified in Appendix A
to this Agreement, unless the context requires otherwise.
<PAGE> 2
1.2 CONSTRUCTION OF TERMS. As used in this Agreement, the terms
"herein," "herewith" and "hereof" are references to this
Agreement, taken as a whole, the term "includes" or "including"
shall mean "including, without limitation," and references to a
"Section", "subsection", "clause", "Exhibit", "Appendix" or
"Schedule" shall mean a Section, subsection, clause, Exhibit,
Appendix or Schedule of this Agreement, as the case may be, unless
in any such case the context requires otherwise. All references to
a given agreement, instrument or other document shall be a
reference to that agreement, instrument or other document as
modified, amended, supplemented and restated through the date as
of which such reference is made, and reference to a law,
regulation or ordinance includes any amendment or modification
thereof. A reference to a Person includes its successors and
permitted assigns. The singular shall include the plural and the
masculine shall include the feminine, and vice versa.
1.3 DRAFTING INTERPRETATIONS. Preparation of this Agreement has been a
joint effort of both the Parties and the resulting document shall
not be construed more severely against one of the Parties than
against the other.
1.4 DOCUMENTS INCLUDED. This Agreement consists of this document and
the Exhibits which are listed in the Table of Contents and
attached hereto or shall be attached hereto in accordance with the
provisions hereof, and which are specifically incorporated herein
and made a part hereof by this reference.
1.5 CONFLICTING PROVISIONS. In the event of any conflict between this
document and any Exhibit hereto, the terms and provisions of this
Agreement, as amended from time to time, shall control. In the
event of any conflict among the Exhibits, the Exhibit of the
latest date mutually agreed upon by the Parties shall control.
1.6 ENTIRE AGREEMENT. This Agreement together with the other Project
Agreements set forth the full and complete understanding of the
Parties relating to the subject matter of each such Project
Agreement as of the Effective Date, and supersede any and all
negotiations, other agreements and representations made or dated
prior thereto with respect to such subject matter thereof.
2. PURCHASE AND SALE OF ELECTRICAL ENERGY AND ELECTRICAL CAPACITY
2.1 EXCLUSIVE SOURCE. Except as provided in Section 2.3.2.1, from and
after the Commercial Operation Date and continuing for the
remainder of the Term, (a) the Partnership shall sell and deliver
to Phillips, and
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Phillips shall purchase and accept from the Partnership,
Electrical Energy at the Electrical Energy Point of Delivery, and
(b) the Partnership shall make available and Phillips shall
reserve electrical capacity generated by the Project, all in
accordance with the terms and conditions set forth in this Section
2. Phillips shall not purchase any electrical energy or capacity
for HCC from any other source, without the consent of the
Partnership, except as set forth in Section 2.8, as contemplated
by the Standby Agreement, if Phillips has electrical energy
requirements in excess of 90 MW or when the Partnership does not
meet its obligations to supply Electrical Energy to Phillips under
this Agreement. In addition, Phillips shall not purchase or use
any equipment for the sole purpose of generating electrical
energy; provided, however, Phillips may purchase or use any
equipment to generate electrical energy derived from the
optimization of its process unit operations.
2.2 PURCHASE AND SALE OBLIGATION FOR ELECTRICAL ENERGY AND
ELECTRICAL CAPACITY.
2.2.1 PURCHASE AND SALE OBLIGATION FOR ELECTRICAL ENERGY. The
Partnership shall sell and deliver to Phillips, and
Phillips shall purchase and accept from the Partnership,
at the Electrical Energy Point of Delivery, (a) all of the
electrical energy requirements of HCC up to 90 MW which
are in excess of any electrical energy permitted to be
generated by HCC from time to time from its process unit
operations under Section 2.1 above, and (b) at Phillips'
option, Electrical Energy in excess of the amount provided
under (a) above, up to a total of 90 MW; provided,
however, that the Partnership shall deliver up to, but
shall not be obligated to deliver more than, the total of
Firm Capacity and Interruptible Capacity. Notwithstanding
anything to the contrary contained herein, (x) the
commitment by Phillips to purchase Electrical Energy is on
an HCC requirements basis only, with no minimum amount of
Electrical Energy required to be taken by Phillips, and
(y) Phillips may at any time purchase any amounts of
electrical energy in excess of 90 MW from any third party.
2.2.2 PURCHASE AND SALE OBLIGATION FOR ELECTRICAL CAPACITY. The
Partnership shall make available to Phillips, and Phillips
shall reserve from the Partnership, the Firm Capacity and
the Interruptible Capacity.
2.3 ELECTRICAL PAYMENT.
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2.3.1 VARIABLE FUEL PAYMENT AND VARIABLE O&M PAYMENT. During the
Initial Term or any Phillips Extension Term, for any
Electrical Energy delivered to Phillips by the Partnership
for each Billing Period, Phillips shall pay the Variable
Fuel Payment and the Variable O&M Payment (a) at the rates
set forth in Exhibit A, or (b) if a price adjustment has
occurred pursuant to Section 2.8, at the rates specified
in the Pricing Notice Response. During any Renewal Term
for any Electrical Energy delivered to Phillips by the
Partnership, Phillips shall pay for Electrical Energy at
the price mutually agreed upon between the Parties.
2.3.2 ELECTRICAL CAPACITY PAYMENT.
2.3.2.1 COMMENCEMENT OF FIRM ELECTRICAL CAPACITY PAYMENTS.
Phillips shall pay the Partnership, in accordance with the
provisions of Section 5.2, the Electrical Capacity
Payment. Thirteen (13) months prior to the anticipated
Commercial Operation Date, the Partnership shall notify
Phillips of the anticipated Commercial Operation Date.
Phillips shall use reasonable efforts to terminate any
agreements with HL&P for the supply of electrical energy
(other than the Standby Agreement) and to arrange for the
Standby Agreement to be effective as of such anticipated
Commercial Operation Date. Notwithstanding Section 2.1 and
Section 5.2, Firm Electrical Capacity Payments shall begin
as of the date Phillips is able to terminate payments
under the HL&P agreements in effect immediately prior to
the Commercial Operation Date. In any event, the Firm
Electrical Capacity Payments shall commence no later than
thirty (30) days after the Commercial Operation Date.
2.3.2.2 ADJUSTMENTS TO ELECTRICAL CAPACITY PAYMENTS.
Phillips shall pay the Electrical Capacity Payments
through the Capacity Payment Termination Date; provided,
however, that the Electrical Capacity Payment shall be (a)
adjusted as provided in a Pricing Notice Response
delivered pursuant to Section 2.8.2, or (b) terminated in
the event of an HCC Shutdown on the terms described in
Section 5.2. During any period when a Force Majeure Event
prevents the Partnership from delivering Electrical Energy
to Phillips under this Agreement and Phillips is unable to
continue to obtain electrical energy under the tariff in
effect under the Standby Agreement at the time of the
Force Majeure Event, the Partnership shall pay to Phillips
the incremental increased
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demand costs Phillips actually pays under any alternate
tariffs as may be applicable in the circumstances over the
demand costs otherwise payable by Phillips under the
Standby Agreement. If the Partnership fails to make such
payments within fifteen (15) days after receipt of an
invoice from Phillips together with evidence of payment by
Phillips, Phillips may, at its option, offset the amount
of the incremental increase in demand payments it actually
pays against the Electrical Capacity Payment otherwise due
hereunder for such period of time as the Partnership fails
to either supply Electrical Energy or reimburse Phillips
for its increased demand costs.
2.3.3 PAYMENT FOR USE OF EXCESS ELECTRICAL ENERGY. If at any
time Phillips takes Electrical Energy from the Partnership
in excess of the total of 80 MVA plus the number of MVA
calculated pursuant to Section 2.4.2 of Interruptible
Capacity after integrating (averaging) amounts taken over
any hour period, Phillips shall pay the Partnership for
the exceeded amount the payment specified in Exhibit A.
The Partnership shall notify Phillips promptly after such
time as the Partnership determines that the electrical
capacity of the Project is fully committed.
2.4 INTERRUPTIBLE CAPACITY.
2.4.1 SCHEDULING INTERRUPTIBLE CAPACITY. Phillips shall furnish
the Partnership with an annual forecast of its planned
daily profile of its electrical requirements not later
than December 1st each year for the following calendar
year, indicating in such forecast its major planned
outages for the year. Phillips may update the annual
forecast if any changes in the annual forecast are
anticipated. The Partnership shall reserve Interruptible
Capacity for the megawatts Phillips indicates it will
require in the most recent forecast received by the
Partnership at least three (3) days in advance of the
effective change in the forecast.
2.4.2 MVA CALCULATION. Interruptible Electrical Capacity
Payments for each Billing Period shall be based upon the
greater of the following: (a) the number of MVA, on an
integrated (averaged) basis during any one-hour period of
maximum use above 80 MVA in a Billing Period; (b) the
maximum number of MVA requested by Phillips in such
Billing Period in the last timely notice received by the
Partnership as specified in Section 2.4.1 above; and (c)
five (5) MVA.
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2.5 STANDBY ELECTRICAL AGREEMENT.
2.5.1 STANDBY AGREEMENT. Prior to the Commercial Operation Date,
Phillips shall enter into a Standby Agreement pursuant to
which Phillips shall have Contingency Failure Protection
with regard to electrical energy. Neither Party shall have
any liability under a standby agreement entered into by
the other.
2.5.2 DEMAND PAYMENT ADJUSTMENT. If Phillips takes electrical
energy under the terms of the Standby Agreement, solely
because the Partnership failed to keep the Project at a
95% Availability Percentage, resulting in an upward
pricing adjustment in the demand payments under the
Standby Agreement, the Partnership shall reimburse
Phillips for the actual incremental amount of increase in
such demand payments Phillips is required to pay as a
result of the Project's failure to operate at a 95%
Availability Percentage within fifteen (15) days after
receipt of a copy of an invoice for any such increased
amount and evidence of payment of the applicable amount by
Phillips.
2.6 PAYMENT ADJUSTMENT FOR FAILURE TO SUPPLY.
2.6.1 ENERGY PAYMENT ADJUSTMENT. Notwithstanding any other
provision of this Agreement, the Partnership is obligated
to supply Phillips with Electrical Energy no more than 95%
of the time during any COD Year. If the Project does not
have Availability to supply Electrical Energy to Phillips,
Phillips shall obtain electrical energy pursuant to the
terms of the Standby Agreement, and the Partnership shall
not be deemed to be in default hereunder for any failure
to supply, even if the Project Availability Percentage is
less than 95% in a COD Year. The Partnership shall,
however, reimburse Phillips for any actual incremental
electrical energy costs to Phillips for any COD Year in
which the Project fails to achieve 95% Availability by
paying Phillips the amount of the Availability Debit for
such COD Year; provided that if any Availability Credits
have accrued during the applicable Availability Cycle
prior to any COD Year in such Availability Cycle in which
the Project fails to achieve 95% Availability, such
Availability Credits shall be used to offset the
Availability Debit otherwise payable to Phillips.
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2.6.2 REIMBURSEMENT FOR INCREMENTAL COSTS Within thirty (30)
days after the end of each COD Year, the Partnership shall
determine and advise Phillips of the Availability
Percentage of the Project for the preceding year. If the
Availability Percentage exceeds 95%, the Partnership shall
calculate and record an Availability Credit for such COD
Year. If the Availability Percentage is less than 95%, the
Partnership shall calculate and pay Phillips the amount of
the Availability Debit for such COD Year, after first
offsetting the amount of any Availability Credits which
may have accrued during the applicable Availability Cycle,
but were not used previously as offsets. The Partnership
shall pay such amount within forty-five (45) days after
the end of the COD Year.
2.7 ADDITIONAL ELECTRICAL ENERGY. If at any time or from time to time,
the Project has capacity in excess of 90 MW which has not been
sold to Third-Party Purchasers and Phillips requires Electrical
Energy in excess of 90 MW, Phillips may purchase Electrical Energy
and electrical capacity on terms and conditions negotiated by the
Partnership and Phillips at that time; provided, however, the
Partnership shall not have any obligation to make Electrical
Energy in excess of 90 MW available to Phillips.
2.8 OPTION TO ADJUST PURCHASE OF ELECTRICAL ENERGY AND ELECTRICAL
CAPACITY. Notwithstanding any other provision of this Agreement,
at any time during the Electrical Option Period, Phillips shall
have a one time option to adjust its obligation to purchase from
the Partnership all or a portion of its requirements for
electrical capacity and electrical energy under this Agreement in
accordance with the following provisions.
2.8.1 PRICING NOTICE. At any time during the Electrical Option
Period, Phillips may provide the Partnership with a
Pricing Notice. Phillips shall deliver a copy of the
Electrical Pricing Offer to the Partnership when it
delivers the Pricing Notice. Phillips shall not issue more
than one Pricing Notice during the Electrical Option
Period; provided, however, in the event any Electrical
Pricing Offer is withdrawn at any time prior to the
issuance of a Pricing Notice Response by the Partnership,
Phillips shall have the right to issue another Pricing
Notice during the Electrical Option Period.
2.8.2 RIGHT OF FIRST REFUSAL. The Partnership shall have a right
of first refusal to match the terms and conditions
required to be specified in an Electrical Pricing Offer
for a ninety (90) day period after receipt of the Pricing
Notice; provided, however,
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<PAGE> 8
that the Partnership will be deemed to have matched the
pricing in the Electrical Pricing Offer if the
Partnership's price for energy and capacity as delivered
to Phillips at the point of interconnection to HCC is
equal to or less than the "all in" price in the Electrical
Pricing Offer for energy and capacity as delivered to
Phillips at the point of interconnection at HCC (i.e.,
including all transmission or transportation charges and
other charges in the Electrical Pricing Offer in addition
to commodity, demand or reservation charges). The
Partnership may exercise such right of first refusal by
delivering, within the ninety (90) day response period, a
Pricing Notice Response to Phillips setting forth the
adjusted pricing. Thereafter, the Partnership shall
continue to be the exclusive supplier of all required
electrical capacity and energy at HCC on and subject to
all of the terms and conditions set forth in this
Agreement, except that from and after twenty-four (24)
months after the Partnership receives the Pricing Notice,
the pricing hereunder shall be adjusted to those terms set
forth in the Pricing Notice Response for the remainder of
the Initial Term.
2.8.3 ADJUSTMENT TERMS. If the Partnership either fails to
deliver a Pricing Notice Response within the ninety (90)
day response period or notifies Phillips that the
Partnership will not issue a Pricing Notice Response,
Phillips' obligation to purchase (and the Partnership's
obligation to supply) electrical capacity and Electrical
Energy hereunder for the number of megawatts specified in
the Electrical Pricing Offer shall terminate as of
twenty-four (24) months after the Partnership receives the
Pricing Notice, and the Firm Electrical Capacity Payment
shall be reduced as set forth in Exhibit A for each annual
megawatt no longer supplied by the Partnership. In such
event, if the Partnership remains obligated to supply any
Firm Capacity to Phillips, Phillips shall take its
requirements for HCC first from the Partnership, and then
from the alternate source. Notwithstanding any termination
of the obligation to purchase and supply all or a portion
of the electrical capacity and Electrical Energy provided
for hereunder, all other provisions of this Agreement
shall remain in full force and effect, including the
obligation to purchase and supply Electrical Energy and
electrical capacity not covered by the Pricing Notice, as
well as Steam and Steam capacity on the terms described in
Section 3.
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3. PURCHASE AND SALE OF STEAM AND STEAM CAPACITY
3.1 EXCLUSIVE SOURCE. From and after the Commercial Operation Date
and continuing for the remainder of the Term, (a) the
Partnership shall sell and deliver to Phillips, and Phillips
shall purchase and accept from the Partnership, Steam at the
Point of Delivery for Steam, and (b) the Partnership shall make
available and Phillips shall reserve steam capacity from the
Project, all in accordance with the terms and conditions set
forth in this Section 3. Phillips shall not purchase any steam
or steam capacity for HCC from any other source, without the
consent of the Partnership, except to the extent Phillips
requires steam in excess of the Maximum Steam Requirement or
during any period when the Partnership does not meet its
obligations to supply Steam to Phillips under this Agreement,
even if due to a Force Majeure Event. In addition, Phillips
shall not purchase or use equipment for the sole purpose of
generating steam; provided, however, Phillips may purchase or
use any equipment to generate steam derived from the
optimization of its process unit operations.
3.2 PURCHASE AND SALE OBLIGATION FOR STEAM AND STEAM CAPACITY.
3.2.1 PURCHASE AND SALE OBLIGATION. The Partnership shall
sell and deliver to Phillips, and Phillips shall
purchase and accept from the Partnership, all the
Steam requirements of HCC up to the Maximum Steam
Requirement which are in excess of the amount of
steam permitted to be generated by HCC from time to
time in connection with process unit operations under
Section 3.1 above. Notwithstanding the foregoing,
except for a Force Majeure Event or HCC Shutdown, the
Partnership shall be obligated to deliver, and
Phillips shall be obligated to request, take and
productively use not less than the Minimum Steam
Requirement, nor more than the Maximum Steam
Requirement. Notwithstanding anything to the contrary
contained herein, (a) the commitment by Phillips to
purchase Steam in excess of the Minimum Steam
Requirement is on an HCC requirements basis only,
with no other minimum amount of Steam required to be
taken by Phillips, and (b) Phillips may at any time
purchase any amounts of steam in excess of the
Maximum Steam Requirement from any third party.
3.2.2 PURCHASE AND SALE OBLIGATION FOR STEAM CAPACITY. The
Partnership shall make available to Phillips, and
Phillips shall reserve from the Partnership, steam
capacity sufficient to enable the Partnership to
deliver Steam up to the Maximum Steam Requirement.
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3.3 CHARACTERISTICS OF STEAM. The Steam delivered by the
Partnership to Phillips at the Point of Delivery for Steam
shall conform to the Steam Specifications.
3.4 STEAM PAYMENT.
3.4.1 VARIABLE STEAM PAYMENT. From and after the Commercial
Operation Date and continuing for the Initial Term or
any Phillips Extension Term, for any Steam delivered
to Phillips by the Partnership, for each Billing
Period Phillips shall pay the Variable Steam Payment
at the rates set forth in Exhibit B attached hereto.
During any Renewal Term, for any Steam delivered to
Phillips by the Partnership, for each Billing Period
Phillips shall pay the Variable Steam Payment
mutually negotiated between the Parties.
3.4.2 FIXED STEAM O&M PAYMENT. From and after the
Commercial Operation Date and continuing for the
Initial Term or any Phillips Extension Term, Phillips
shall pay the Fixed Steam O&M Payment on a quarterly
basis in accordance with the provisions of Section
5.2; provided, however, the Fixed Steam O&M Payment
shall be suspended in accordance with Section 5.2 in
the event of an HCC Shutdown.
3.4.3 FIXED STEAM CAPACITY PAYMENT. From the Commercial
Operation Date through the Capacity Payment
Termination Date, Phillips shall pay the Partnership
the Fixed Steam Capacity Payment on a quarterly basis
in accordance with the provisions of Section 5.2;
provided, however, the Fixed Steam Capacity Payment
shall be suspended in accordance with Section 5.2 in
the event of an HCC Shutdown.
3.5 ADDITIONAL STEAM REQUIREMENT. If at any time after the
Commercial Operation Date the Project has steam capacity in
excess of the Maximum Steam Requirement, and Phillips requires
such additional steam and steam capacity, Phillips may purchase
such amounts on terms and conditions negotiated by the
Partnership and Phillips at that time; provided, however, the
Partnership shall not have any obligation to provide steam in
excess of the Maximum Steam Requirement to Phillips.
4. CONDENSATE RETURN
4.1 TRANSPORTATION OF STEAM AND CONDENSATE. Phillips shall take
delivery of and transport Steam from the Point of Delivery for
Steam into the HCC steam distribution system and shall maintain
a Steam line and a Condensate line properly supported and
insulated as required for the
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transportation of Steam and Condensate within the HCC steam
distribution system. The Partnership shall not be under any
obligation to inspect, maintain or repair the HCC steam
distribution system.
4.2 CONDENSATE RETURN. During any Billing Period, Phillips shall
return Condensate which meets the Condensate Return
Specifications to the Partnership at the Point of Delivery for
Condensate, in an amount equal to approximately fifty percent
(50%) of the Steam delivered to Phillips. The Partnership shall
monitor the Condensate delivered to the Partnership to
determine whether the Condensate meets the Condensate Return
Specifications. In the event any Condensate returned by
Phillips fails to meet the Condensate Return Specifications,
the Partnership shall be under no obligation to accept such
Condensate.
4.3 FAILURE TO SUPPLY CONDENSATE. If Phillips fails to return to
the Partnership approximately fifty percent (50%) of the Steam
delivered to Phillips by the Partnership as Condensate meeting
the Condensate Return Specifications, then the Partnership
shall, if possible, take and de-mineralize raw water (whether
supplied by a third party or is Raw Water supplied by Phillips)
in the Partnership's water treatment facility, in amounts
sufficient to permit the Partnership to continue to supply
Steam and Electrical Energy, to Phillips. The Partnership's
sole remedy for Phillips' failure to return to the Partnership
approximately fifty percent (50%) of the Steam as Condensate
shall be reimbursement (a) for the cost of such additional raw
water, and (b) for any additional chemical costs incurred by
the Partnership to de-mineralize such raw water.
4.4 OPERATION OF THE STANDBY BOILERS DUE TO PHILLIPS' FAILURE TO
SUPPLY RAW WATER AND CONDENSATE. The provisions of this Section
4.4 shall not apply unless Phillips is the sole supplier of raw
water to the Project under the Facility Services Agreement.
Phillips shall at all times use its Best Commercial Efforts to
ensure that the Partnership has sufficient Raw Water to both
make Steam and operate the Power Plant at capacity; provided
however, Phillips shall have no obligation to provide Raw Water
in excess of the maximum amounts required to be supplied under
the Facility Services Agreement. If the Partnership must shut
down its turbines solely because Phillips has failed to supply
sufficient Raw Water in accordance with Phillips' obligations
under the Facility Services Agreement and this Agreement, then
the Partnership shall use its Best Commercial Efforts to
continue to supply Steam sufficient to meet the Steam
requirements of HCC by operation of the Standby Boilers;
provided, however, Phillips shall pay the Partnership the
additional incremental costs for the operation of the Standby
Boilers.
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4.5 INTERRUPTION OF WATER SUPPLY. The Partnership shall have
storage capacity at the Project Site sufficient to enable it to
supply 200,000 lbs of Steam for at least thirty-six (36) hours
after an interruption in the supply of raw water. Under any
circumstances, if the interruption in the supply of raw water
to the Power Plant is of greater duration, Phillips and the
Partnership shall attempt to arrange for the Partnership to
obtain water from Phillips to enable the Partnership to
continue to make and deliver Steam.
5. BILLING AND PAYMENT
5.1 MONTHLY BILLING CYCLE FOR STEAM, ELECTRICAL ENERGY AND STANDBY.
The Partnership shall read the Metering Devices installed
pursuant to Section 8.1 monthly, and shall provide Phillips
with an invoice for each Billing Period setting forth the
amount of Steam and Electrical Energy delivered to Phillips
during such Billing Period and the amount of the Variable Fuel
Payment, Variable O&M Payment and Variable Steam Payment to be
paid by Phillips pursuant to Sections 2.3.1 and 3.4.1
respectively.
5.2 QUARTERLY PAYMENT FOR CAPACITY AND FIXED STEAM O&M. Except as
otherwise provided pursuant to Section 2.3.2.1, as of the
Commercial Operation Date and thereafter on a quarterly basis,
which quarters may, at the option of the Partnership, coincide
with the date payment is due to any Project Financing Entities,
the Partnership shall invoice Phillips and Phillips shall pay
one quarter of the annual Fixed Steam O&M Payment, one quarter
of the annual Fixed Steam Capacity Payment, one quarter of the
annual Firm Electrical Capacity Payment plus all Interruptible
Electrical Capacity Payments payable for the applicable
quarter, in arrears, for any whole or partial calendar quarter
occurring as of or after the Commercial Operation Date. The
Fixed Steam O&M Payment shall be payable during the Initial
Term or any Phillips Extension Term. The Fixed Steam Capacity
Payment and the Electrical Capacity Payment shall be payable
from the Commercial Operation Date through the Capacity Payment
Termination Date. If the Commercial Operation Date, the
Capacity Payment Termination Date or any termination date of
this Agreement does not coincide with the last day of a
calendar quarter, the first such payment and/or last such
payment, as applicable, shall be prorated on a daily basis over
a ninety (90) day period. In the event of an HCC Shutdown,
notwithstanding any termination of this Agreement pursuant to
Section 17.3, the Fixed Steam O&M Payment, Fixed Steam Capacity
Payment and the Electrical Capacity Payment shall continue to
be payable through the last day of the calendar year in which
the HCC Shutdown occurs, but shall terminate thereafter.
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5.3 PAYMENT OF INVOICES. Each invoice issued by the Partnership
shall be paid by Phillips by electronic funds transfer or by
such other means agreed upon by the Parties as will ensure that
the Partnership receives such payment in good funds (a) on or
before the last day of the month if Phillips receives the
invoice prior to the fifteenth (15th) day of the month, or (b)
within fifteen (15) days after receipt of an invoice at any
later time in the month. If Phillips disputes the correctness
of any statement, information or invoice submitted by the
Partnership hereunder, Phillips shall promptly submit to the
Partnership a written statement detailing the specific items
disputed. If the Parties are unable to reach agreement with
respect to a disputed item, such dispute shall be subject to
further resolution pursuant to the Dispute Resolution
Procedures. Notwithstanding the foregoing, if Phillips disputes
the correctness of any statement or invoice submitted by the
Partnership hereunder, Phillips shall nevertheless make payment
on the basis of the undisputed portion of the statement or
invoice within the time period specified for payment hereunder.
5.4 INTEREST. Amounts not paid by either Party to the other when
due under any provisions of this Agreement, including the
provisions of this Section 5, shall bear interest at the
Delayed Payment Rate from the date such payment is due until
and including the date of payment.
6. OPERATION OF THE PROJECT
6.1 OPERATION OF THE PROJECT. The Parties acknowledge and agree
that the Partnership shall delegate the operation and
maintenance of the Power Plant to Calpine, and that Calpine or
its Affiliates shall be the operator of the Power Plant for at
least a six (6) year period after the Commercial Operation
Date; provided, however that Phillips shall not unreasonably
withhold its consent to another operator during such period if
any Project Financing Entity reasonably requests a change in
the operator of the Power Plant. The Partnership may delegate
the operation and maintenance of the Power Plant after such six
(6) year period only if Phillips consents to another operator,
which consent shall not be unreasonably withheld. Phillips
shall have the absolute right to prohibit a competitor of
Phillips from becoming the operator of the Power Plant.
Notwithstanding any delegation, the Partnership shall remain
responsible to perform its obligations under this Agreement. At
all times after the Commercial Operation Date, the Partnership
shall operate and manage the Power Plant and the Operating
Easement Improvements, and Phillips shall operate and manage
the Development and Construction Easement Improvements, in a
manner consistent with Prudent Operating Practices. The
Partnership shall keep, or cause to be kept, in full force and
effect all Applicable Permits which are
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necessary for the ownership, operation, maintenance, use and
repair of the Power Plant and shall comply with, or cause to be
complied with, all Laws which are applicable to the Partnership
or the Project.
6.2 OPERATING AND COMMUNICATION GUIDELINES. Prior to the Commercial
Operation Date, the Parties shall develop written mutually
agreeable operating and communication procedures to serve as
guidelines for the Parties addressing operating and
communication aspects of mutual interest, including
communication links between the Parties for supplying
information on normal operations, interconnections or
separation, switching and equipment clearances, levels of
operating voltage and power factors, special procedures
required during the testing and initial operation of the
Project and scheduling considerations related to both planned
and emergency outages of the Project and HCC. Such guidelines
shall not override provisions of this Agreement.
6.3 STEAM REDUNDANCY REQUIREMENTS. From and after the Commercial
Operation Date and continuing for the remainder of the Term,
the Partnership shall provide Phillips with firm standby Steam
availability from the Standby Boilers. The Partnership shall
operate the Project, including the Standby Boilers, in
compliance with the Steam Redundancy Requirements.
6.4 STANDBY BOILERS OPERATING RIGHTS.
6.4.1 EXERCISE OF RIGHTS. The Partnership acknowledges that
a reliable supply of Steam is critical to the
efficient and safe operation of HCC and agrees that
the Project shall be operated in such a manner as to
provide a reliable source of Steam to HCC. Phillips
shall be entitled to exercise the Standby Boilers
Operating Rights during the Term of this Agreement if
any of the Partnership, the Project Financing
Entities, or any assignee of either (a) fails for any
reason to supply Steam in accordance with the terms
of this Agreement and the Standby Boilers are capable
of operation or (b) decides to no longer supply Steam
in breach of its obligations to supply Steam
hereunder. If the failure to deliver Steam is the
result of clause (a) above, then Phillips shall have
the right to immediately exercise the Standby Boilers
Operating Rights by sending notice by facsimile to
the Partnership at the Power Plant and as provided in
Section 21.1, or to such other address as the
Partnership may from time to time indicate, and to
the Project Financing Entity and any other assignee
of which Phillips has received notice, that Phillips
has failed to receive Steam and that it intends to
promptly exercise the Standby Boilers Operating
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Rights. If the Partnership is still providing an
uninterrupted supply of Steam but decides to no
longer supply Steam under clause (b) above, then the
Partnership shall immediately notify Phillips in the
quickest possible way (in person or telephone),
confirmed no later than the next Business Day
thereafter in writing, and Phillips shall have the
right to exercise the Standby Boilers Operating
Rights in advance of the actual cessation of Steam
deliveries.
6.4.2 PARTNERSHIP COOPERATION. Upon the exercise by
Phillips of the Standby Boilers Operating Rights, the
Partnership shall use its Best Commercial Efforts to
afford Phillips access to the Project and to assist
Phillips to obtain control of the operation of the
Standby Boilers to the extent necessary to enable
Phillips to exercise the Standby Boilers Operating
Rights.
6.4.3 PARTNERSHIP FUEL GAS. During any period that Phillips
exercises the Standby Boilers Operating Rights, the
Partnership grants Phillips the right, which shall
not be construed as an obligation, to utilize the
Partnership's supply of fuel gas to the extent
available, as reasonably required by Phillips to
operate the Standby Boilers.
6.4.4 REMEDIES AND LIABILITIES. The exercise by Phillips of
the Standby Boilers Operating Rights shall be in
addition to any other remedies available to Phillips
hereunder, shall not affect the running of any of the
cure periods with respect to an Event of Default, and
shall not be deemed an assumption by Phillips of any
liability of the Partnership for the period during
which Phillips exercises the Standby Boilers
Operating Rights. During the exercise of Standby
Boilers Operating Rights, Phillips shall operate the
Standby Boilers in accordance with Prudent Operating
Practices and all Permits and Laws. Phillips shall
have no liability to the Partnership for damages to
the Standby Boilers during the period Phillips
exercises the Standby Boilers Operating Rights unless
such damage is caused by the gross negligence or
willful misconduct of Phillips or the Permitted Steam
Operator(s). In no event shall Phillips' election to
exercise the Standby Boilers Operating Rights be
deemed to constitute a transfer of title to the
Standby Boilers or any of the Partnership's
obligations as owner thereof.
6.4.5 REIMBURSEMENT FOR COSTS AND EXPENSES. The Partnership
agrees to reimburse Phillips for reasonable labor
costs
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and expenses incurred by Phillips in the exercise of
the Standby Boilers Operating Rights.
6.4.6 CESSATION OF STANDBY BOILER OPERATING RIGHTS.
Phillips shall have the right to continue to exercise
the Standby Boilers Operating Rights until the
earlier to occur of (a) such time as the Partnership,
its agent or its assignee assumes operational control
of the Standby Boilers and provides Steam to Phillips
in accordance with the terms of this Agreement, or
(b) Phillips obtains another permanent supply of
steam for HCC, but in no event longer than two (2)
years.
6.4.7 TRAINING. From the Commercial Operation Date and
continuing for the remainder of the Term, the
Partnership shall annually provide a training class
on the operation of the Standby Boilers, at no cost
to Phillips, for up to eight Phillips employees or
agents as potential Permitted Steam Operators. The
Partnership shall not have any obligation to pay
labor costs or related expenses for such Phillips
employees or agents.
6.5 PHILLIPS REPRESENTATIVE. Phillips shall appoint an individual
as the Phillips Representative; provided, however, that
Phillips may at any time in its sole discretion by written
notice to the Partnership designate a substitute or replacement
Phillips Representative. The Phillips Representative shall not
have any authority to amend this Agreement. The Phillips
Representative shall receive all reports required hereunder and
shall be available during normal business hours for
consultations with the Partnership Representative and other
Partnership personnel. The Partnership shall be entitled to
rely upon any consents, approvals or authorizations provided by
the Phillips Representative. No directions or approvals given
by any Phillips personnel other than the Phillips
Representative shall be binding upon Phillips, except that (a)
the Phillips Representative may notify the Partnership in
writing of any alternate representative who may act in the
absence of the Phillips Representative, and (b) the Phillips
Representative, by written notice to the Partnership
Representative, may designate named individuals who shall have
full power and authority to act on behalf of the Phillips
Representative with respect to designated areas of
responsibility.
6.6 THE PARTNERSHIP REPRESENTATIVE. The Partnership shall appoint
an individual as the Partnership Representative; provided,
however, that the Partnership may at any time in its sole
discretion by written notice to Phillips designate a substitute
or replacement Partnership Representative. The Partnership
Representative shall not have any
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authority to amend this Agreement. The Partnership
Representative shall receive required reports, and shall be
available during normal business hours for consultation with
the Phillips Representative and other Phillips personnel.
Phillips shall be entitled to rely upon any consents, approvals
or authorizations provided by the Partnership Representative.
No directions or approvals given by any Partnership personnel
other than the Partnership Representative shall be binding upon
the Partnership, except that (a) the Partnership Representative
may notify Phillips in writing of any alternate representative
who may act in the absence of the Partnership Representative,
and (b) the Partnership Representative, by written notice to
the Phillips Representative, may designate named individuals
who shall have full power and authority to act on behalf of the
Partnership Representative with respect to designated areas of
responsibility.
6.7 OBLIGATION TO PROVIDE AUXILIARY BOILERS. Notwithstanding the
provisions of Section 15, in the event the Standby Boilers are
no longer capable of operation or cannot supply Steam up to the
Maximum Steam Requirement, the Partnership shall within twelve
(12) hours after such damage or destruction rent, and advise
Phillips that it has rented, auxiliary boilers sufficient to
supply Steam up to the Maximum Steam Requirement and that such
boilers will be available for operation within seven (7) days.
In the event the Partnership fails to rent such auxiliary
boilers and notify Phillips as required above, then Phillips
shall have the right, on behalf of and at the Partnership's
cost and expense, to rent and operate auxiliary boilers
sufficient to supply Steam up to the Maximum Steam Requirement.
Phillips may offset any such reasonable costs and expenses
incurred by it against Fixed Steam O&M and Fixed Steam Capacity
Payments due to the Partnership hereunder. The Partnership
shall continue to rent auxiliary boilers sufficient to meet the
steam requirements of HCC which are not in excess of the
Maximum Steam Requirement until the earlier to occur of (a)
such time as the Partnership is capable of providing Steam up
to the Maximum Steam Requirements of HCC or (b) termination of
this Agreement.
7. MAINTENANCE AND REPAIR OF THE PROJECT
7.1 THE PARTNERSHIP'S MAINTENANCE OBLIGATIONS. After the Commercial
Operation Date, the Partnership shall keep and maintain the
Power Plant in good operating condition, consistent with
Prudent Operating Practices, and shall make or cause to be made
all repairs and equipment overhauls necessary to keep the Power
Plant in such condition. The Partnership shall be responsible,
at its expense, for the maintenance, repair and replacement of
(a) the Development and Construction Easement Improvements
through the Commercial
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Operation Date and (b) the Operating Easement Improvements, and
for keeping such improvements in good operating condition,
consistent with Prudent Operating Practices. The Partnership
shall repair and restore operation of the Easement Improvements
for which it has the responsibility to maintain as soon as
reasonably practicable after notice of any failure or damage.
Except under emergency circumstances, the Partnership shall use
its Best Commercial Efforts to schedule any planned maintenance
outages for such Easement Improvements during planned outages
for HCC; provided, however, the Partnership shall not be forced
to accept a maintenance schedule which would conflict with its
obligations to Third Party Purchasers, materially increase
maintenance costs or cause damage to the Power Plant.
7.2 PHILLIPS' MAINTENANCE OBLIGATIONS. After the Commercial
Operation Date, Phillips shall be responsible, at its expense,
for the maintenance, repair and replacement of the Development
and Construction Easement Improvements, and for keeping such
improvements in good operating condition, consistent with
Prudent Operating Practices. Phillips shall repair and restore
operation of the Development and Construction Easement
Improvements as soon as reasonably practicable after notice of
any failure or damage. Except under emergency circumstances,
Phillips shall use its Best Commercial Efforts to schedule any
planned maintenance outages for the Development and
Construction Easement Improvements during planned outages for
the Power Plant; provided, however, Phillips shall not be
forced to accept a maintenance schedule which would conflict
with its obligations to third parties, materially increase
maintenance costs or cause damage to HCC. In the event Phillips
requires that the Development and Construction Easement
Improvements be taken out of service for maintenance, repair or
any other reason on an emergency basis, Phillips shall promptly
notify the Partnership and shall use its Best Commercial
Efforts to minimize any interruption in the delivery of Steam,
Condensate or Water while completing such maintenance or
repairs. Notwithstanding the foregoing provisions of this
Section 7.2, the maintenance costs for the high voltage
equipment at HCC substation 1 shall be shared equally between
the Parties.
7.3 SCHEDULED MAINTENANCE FOR THE POWER PLANT AND HCC. No later
than December 1st of each year the Parties shall exchange
production schedules which identify periods for planned outages
of the Power Plant and HCC. The Parties shall use their
respective Best Commercial Efforts to work together to maximize
efficiencies and minimize downtime for maintenance outages at
both the Power Plant and HCC. The Parties shall notify each
other by telephone as soon as possible concerning the cause and
anticipated duration of any forced outage of their respective
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<PAGE> 19
facilities. Subject to obligations to third parties, whenever
possible, the Parties shall coordinate scheduled maintenance
requiring outages of the Power Plant and HCC. Neither Phillips
nor the Partnership shall be forced to accept a maintenance
schedule which would conflict with its obligations to third
parties, materially increase maintenance costs or cause damage
to the Power Plant, the Easement Improvements or HCC.
7.4 INSPECTION AND OBSERVATION RIGHTS. At any time, upon reasonable
advance notice and the availability of the Project Site manager
or a designee to accompany Phillips, and provided the
Partnership has approved the names of the Phillips authorized
representatives, Phillips and its authorized representatives
shall have the right to enter upon the Project Site and to
obtain access to the Power Plant to inspect and observe the
operation and condition of the Power Plant. Any inspection by
Phillips shall not relieve the Partnership of any of its
obligations under the Project Agreements. Pursuant to the terms
of the Project Agreements, upon reasonable advance notice, the
availability of the HCC Site general manager or a designee to
accompany the Partnership, and provided Phillips has approved
the names of the Partnership's authorized representatives, the
Partnership and its authorized representatives shall have the
right to enter upon the HCC Site and to obtain access to the
Development and Construction Easement Improvements to inspect
and observe the operation and condition of such facilities. Any
inspection by the Partnership shall not relieve Phillips of any
of its obligations under the Project Agreements.
8. METERING
8.1 METERING DEVICES. At the Partnership's expense, the Partnership
shall install or cause to be installed the Metering Devices for
determining the quantity (and any other parameters deemed
appropriate by the Partnership and Phillips) of the Steam and
Electrical Energy delivered by the Partnership under this
Agreement. All such Metering Devices shall be owned and
maintained by the Partnership. Phillips shall provide the
Partnership adequate space for those Metering Devices which are
to be installed at the HCC Site.
8.2 PERIODIC INSPECTION. The Partnership shall inspect and test all
Metering Devices upon installation thereof. In addition, on an
annual basis thereafter or upon the request of Phillips, the
Partnership shall inspect and test each Metering Device and
shall provide Phillips reasonable advance notice of, and shall
permit an authorized representative of Phillips to be present
at, any such inspection or test. The cost and expense of any
such inspection or test shall be paid by the
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<PAGE> 20
Partnership. If a Metering Device is found to be defective or
inaccurate, it shall promptly be adjusted, calibrated, repaired
or replaced by the Partnership at the Partnership's cost and
expense. If at any time Phillips desires to independently test
the Metering Devices, Phillips shall have the right to test a
Metering Device upon reasonable advance notice to the
Partnership and upon the availability of the Project Site
manager or a designee to accompany Phillips. Phillips shall
bear the cost of any such testing if the Metering Device is
determined to be accurate within the tolerances indicated in
Section 8.3, but the Partnership shall otherwise bear the cost
of such testing.
8.3 RETROACTIVE ADJUSTMENTS. If a Metering Device fails to
register, or if the measurement made by a Metering Device is
found upon testing to be inaccurate by an amount exceeding plus
or minus two percent (2%) of full scale with respect to a
Metering Device measuring Steam, or by an amount exceeding plus
or minus one half of one percent (.5%) with respect to a
Metering Device measuring Electrical Energy, an adjustment
shall be made correcting all measurements of Steam and
Electrical Energy made by the inaccurate or defective Metering
Device during the Adjustment Period. If the Parties are unable
to agree on the amount of the adjustment to be applied to the
Adjustment Period, the amount of the adjustment shall be
determined (a) by correcting the error if the percentage of
error is ascertainable by calibration, tests or mathematical
calculation, or (b) if not so ascertainable, by estimating on
the basis of deliveries under similar conditions during periods
when the Metering Device was registering accurately. Upon the
determination of the amount of any adjustment, Phillips shall
pay to the Partnership any additional amounts then due for
deliveries of Steam or Electrical Energy during the Adjustment
Period at such time as other payments are due for the Billing
Period in which the determination is made, or Phillips shall be
entitled to a credit against the next subsequent payments due
for deliveries of Steam or Electrical Energy, whichever case is
applicable.
8.4 ACCESS TO METERING DEVICES. Pursuant to the terms of the
Project Agreements, upon reasonable advance notice, the
availability of the HCC Site general manager or a designee to
accompany the Partnership, and provided Phillips has approved
the names of the Partnership's authorized representatives, the
Partnership and its authorized representatives shall have the
right to enter upon the HCC Site and to obtain access to the
Metering Devices owned and maintained by the Partnership on the
HCC Site to read, inspect, test, repair and remove such
Metering Devices.
9. REVIEW MEETINGS
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After the Commercial Operation Date, unless otherwise mutually agreed by
the Parties, the Partnership shall conduct a quarterly Review Meeting with
Phillips to discuss information pertinent to the operation or maintenance of the
Project or any other matters pertinent to the performance of the Parties under
the Project Agreements. Review Meetings shall take place at the Project Site,
unless otherwise agreed by the Phillips Representative and the Partnership
Representative.
10. SALES TO THIRD PARTY PURCHASERS
The Parties acknowledge that the Power Plant is intended to have an
aggregate generating capacity in excess of the Firm Capacity and Interruptible
Capacity committed to Phillips pursuant to this Agreement. The Partnership shall
be entitled at any time, in its sole discretion, to make deliveries and sales of
such excess electrical energy and electrical capacity from the Power Plant to
HL&P and other Third-Party Purchasers under short-term or long-term
arrangements. The Partnership shall have sole responsibility for the marketing
and sale of such electrical energy and electrical capacity to HL&P and
Third-Party Purchasers. Any sales to Third-Party Purchasers shall be consistent
with the Partnership's obligations under this Agreement and shall not adversely
affect deliveries of Electrical Energy or Firm Capacity and Interruptible
Capacity to Phillips hereunder.
11. TERM OF AGREEMENT
11.1 TERM. This Agreement shall be in effect for the Initial Term
and any Renewal Term or Phillips Extension Term, unless
terminated earlier in accordance with the other provisions of
this Agreement.
11.2 RENEWAL TERM. Three (3) years prior to the end of the Initial
Term, the Parties shall meet and negotiate for such terms,
conditions and pricing for the renewal of the Project
Agreements as may be mutually acceptable to the Parties. If the
Parties reach a mutual agreement on the terms, conditions and
pricing for extending the Initial Term of the Project
Agreements, then the Project Agreements shall be extended on
such negotiated terms for a Renewal Term.
11.3 PHILLIPS EXTENSION TERM. In the event the Parties can not reach
mutual agreement under Section 11.2, then Phillips shall have
the option, exercisable by delivering a written notice to the
Partnership no later than two (2) years prior to the end of the
Initial Term, to extend the Initial Term of all of the Project
Agreements in effect as of the last day of the Initial Term for
the Phillips Extension Term upon the same terms and conditions
as are applicable as of the end of the Initial Term, except
that the price for Electrical Energy and Steam shall not
include the Electrical Capacity Payment or Fixed Steam Capacity
Payment. If during the Electrical Option Period Phillips
exercised the option to adjust as set forth in Section 2.8, the
Partnership shall notify Phillips of any
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uncommitted electrical energy and electrical capacity up to 90
MW which may become available during the Phillips Extension
Term and the Parties may negotiate regarding the price of any
such electrical energy and capacity. If Phillips does not elect
to extend the Project Agreements for the Phillips Extension
Term, the Term of this Agreement shall end upon the expiration
or other termination of the Initial Term.
12. INSURANCE
12.1 INSURANCE COVERAGES. From after the earlier of Financial
Closing or the Equity Commitment Date, the Partnership shall,
at all times during the Term of this Agreement or any other
Project Agreement, provide and maintain the types and amounts
of insurance as set forth in this Section 12. In the event any
insurance (including the limits thereof) hereby required to be
maintained is not reasonably available or obtainable on a
commercially reasonable basis in the commercial insurance
market, the Partnership may request Phillips to agree that such
requirements be reduced or eliminated for a specified period,
and Phillips shall not unreasonably withhold its agreement to
waive such requirements for the specified period. The
Partnership shall procure at its own expense, and shall
maintain in full force and effect during the Term of this
Agreement or any other Project Agreement (or as otherwise
provided in this Section 12) with insurance carriers (with the
exception of captive insurance companies used as provided in
Section 12.8) having an A.M. Best rating of B++VII or better or
of recognized responsibility satisfactory to Phillips, the
types and amount of insurance and with limits and coverages no
less than those set forth below.
12.1.1 WORKERS' COMPENSATION INSURANCE. Workers'
Compensation insurance as required by state laws, and
Employer's Liability (including Occupational Disease)
coverage with limits of One Million Dollars
($1,000,000).
12.1.2 COMMERCIAL GENERAL LIABILITY INSURANCE. Commercial
General Liability insurance with a combined single
limit of not less than One Million Dollars
($1,000,000) per occurrence. Such coverage shall
include Premises/Operations, Broad Form Property
Damage and Personal Injury, Products-Completed
Operations, Explosion, Collapse and Underground
Hazards coverage, Broad Form Contractual Liability
and Independent Contractors Liability.
12.1.3 AUTOMOBILE LIABILITY INSURANCE. Automobile Liability
Insurance including coverage for owned, non-owned and
hired
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automobiles with a combined single limit of not less
than One Million Dollars ($1,000,000) per occurrence.
12.1.4 EXCESS/UMBRELLA LIABILITY INSURANCE. Excess/Umbrella
Liability insurance covering claims in excess of the
underlying insurance described in Sections 12.1.1
through 12.1.3, with a combined single limit of
Twenty-Nine Million Dollars ($29,000,000) per
occurrence.
The amounts of insurance required in Sections 12.1.1 through 12.1.4 may be
satisfied by purchasing coverage in the amounts specified or by any combination
thereof, so long as such insurance meets the requirements specified herein.
12.2 ENDORSEMENTS. All policies of insurance described in Sections
12.1.1 through 12.1.4 to be maintained by the Partnership shall
be written or endorsed as follows:
12.2.1 WAIVER OF SUBROGATION. With respect to Workers'
Compensation/Employer's Liability Insurance, to
provide that the insurer (a) shall waive for the
benefit of Phillips (i) all rights of subrogation
against Phillips, its Affiliates, co-venturers, or
their directors, officers, employees or agents, for
payment under such policies, (ii) any right of
set-off and counterclaim, and (iii) any other right
to deduction whether by attachment or otherwise by
any Person to or for whom the insurer pays monies or
other benefits, and (b) in the event and to the
extent that the Parties agree that such provisions
are available on commercially reasonable terms, shall
assign and relinquish to Phillips such rights of
recovery, including any rights of liens;
12.2.2 SEVERABILITY. To provide a severability of interest
of the cross liability clause;
12.2.3 PRIMARY COVERAGE. That the insurance shall be primary
and not excess to or contributing with any insurance
or self-insurance maintained by Phillips; and
12.2.4 ADDITIONAL INSURED. With the exception of the
insurance required under Section 12.1.1, to name
Phillips, its Affiliates and co-ventures at HCC, and
their directors, officers, employees and agents, as
additional insureds with respect to any injury or
damage arising from any work or services performed by
the Partnership, its Affiliates, their contractors or
agents under the Project Agreements or the presence
of the Partnership, its Affiliates, their contractors
or agents, on Phillips' premises.
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12.3 ALL-RISK PROPERTY INSURANCE.
12.3.1 BUILDER'S ALL-RISK INSURANCE AND ALL-RISK PROPERTY
AND BOILER AND MACHINERY INSURANCE. The Partnership
shall procure and maintain at its own expense (a)
Builder's All-Risk Insurance covering physical loss
or damage to the Project and its assets (without an
exclusion for resultant damage from defective
materials and parts and with limits not less than the
full replacement value of the Project, including all
assets on or off the Project Site or in transit) and
(b) effective upon the Commercial Operation Date,
All-Risk Property and Boiler and Machinery insurance
covering physical loss or damage during the operation
of the Project. The All-Risk Property and Boiler and
Machinery insurance shall not contain an exclusion
for resultant damage from defective materials and
parts. Such insurance shall have limits not less than
the Estimated Maximum Loss of the Project and shall
include coverage for Three Million Dollars
($3,000,000) for extra expense which would be
incurred by the Partnership in supplying an alternate
source of steam to Phillips in the event such steam
was not available from the Project.
12.3.2 WAIVER OF SUBROGATION. The insurance required in this
Section 12.3 shall be (a) written or endorsed to
provide for a waiver of subrogation for the benefit
of Phillips, its Affiliates or co-venturers at HCC,
and their directors, officers, employees and agents,
and (b) provided by insurance carriers with an A.M.
Best rating of B++VII or shall be of recognized
responsibility satisfactory to Phillips.
12.4 CONTRACTORS AND SUBCONTRACTORS. The Partnership shall at all
times during the Term of this Agreement or any other Project
Agreement, cause every contractor or subcontractor employed by
the Partnership to carry insurance of types and amounts
necessary to cover risks inherent in the work or services being
performed by such contractors or subcontractors. Coverages for
completed operations under the Commercial General Liability
insurance provided by the prime general contractor and its
subcontractors during the construction of the Project shall
remain in effect for a period of at least two (2) years
following the Commercial Operation Date. Alternatively, the
Partnership may arrange any or all insurance policies on behalf
of the contractors and subcontractors. When requested by
Phillips, the Partnership shall furnish Phillips with
certificates of insurance evidencing coverage for each
contractor and subcontractor.
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12.5 PHILLIPS INSURANCE COVERAGES. At all times during the Term of
this Agreement or any other Project Agreement, Phillips, its
Affiliates and co-venturers, and insurers shall waive (a) any
right of recovery which Phillips or the insurer may have or
acquire against the Partnership, its Affiliates, or their
directors, officers, employees or agents, for payment under
those policies or coverages set forth below and (b) any right
of subrogation which Phillips or the insurers may have or
acquire for payments to any Person who asserts a claim against
the Partnership, its Affiliates, or their directors, officers,
employees or agents, by any Person to or for whom the insurer
pays monies or other benefits:
12.5.1 WORKERS' COMPENSATION INSURANCE. Workers'
Compensation Insurance as required by state law and
Employer's Liability Insurance (including
Occupational Disease) coverage with limits of One
Million Dollars ($1,000,000).
12.5.2 COMMERCIAL GENERAL LIABILITY INSURANCE. Commercial
General Liability Insurance with a combined single
limit of not less than One Million Dollars
($1,000,000) per occurrence. Such coverage shall
include Premises/Operations, Broad Form Property
Damage and Personal Injury, Products-Completed
Operations, Explosion, Collapse and Underground
Hazards coverage, Broad Form Contractual Liability
and Independent Contractors Liability.
12.5.3 AUTOMOBILE LIABILITY INSURANCE. Automobile Liability
insurance, including coverage for owned, non-owned
and hired automobiles with a combined single limit of
not less than One Million Dollars ($1,000,000) per
occurrence.
12.5.4 EXCESS/UMBRELLA LIABILITY INSURANCE. Excess/Umbrella
Liability insurance covering claims in excess of the
underlying insurance described in Sections 12.5.1
through 12.5.3 with a combined single limit of
Twenty-Nine Million Dollars ($29,000,000) per
occurrence.
12.5.5 PROPERTY INSURANCE. All-Risk Property Insurance which
shall cover assets at HCC in an amount of not less
than Two Hundred Million Dollars ($200,000,000).
Phillips shall have the right to self-insure any or part of the coverage
shown in this Section 12.5. In the event the long term senior unsecured
debt securities of Phillips fall below both BBB- by Standard & Poor's
Corporation and Baa3 by Moody's Investors Service, Phillips will procure
insurance in excess of One Million Dollars ($1,000,000) up to Phillips'
insurance captive's then full retentions
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from insurers not affiliated with Phillips which have a Best rating of
no less than A-10.
12.6 EVIDENCE OF INSURANCE. Prior to the initiation or performance
of any work or services under the Project Agreements, the
Partnership and Phillips shall furnish to each other
certificates of insurance from each insurance carrier showing
that the above required insurance and endorsements are in full
force and effect, the amount of the carrier's liability
thereunder, and further providing that the insurance will not
be canceled, materially changed or not renewed until the
expiration of at least thirty (30) days (or ten (10) days in
the case of cancellation due to non-payment of premiums) after
written notice of such cancellation, material change or
nonrenewal has been received by Phillips or the Partnership,
respectively; provided, however, that in the event and to the
extent that Phillips, in its sole discretion, shall self-insure
any such coverages, Phillips shall provide to the Partnership
written notice of such self-insurance.
12.7 DISCLAIMER. The insurance requirements set out in this Section
12 are not a representation that the coverage and limits
provided thereby are sufficient to protect the interest of the
Partnership or Phillips and shall not be deemed as a limitation
on the Partnership's or Phillips' liability.
12.8 PLACEMENT OF INSURANCE COVERAGE WITH CAPTIVE.
12.8.1 PHILLIPS' CAPTIVE INSURER. Phillips shall have the right
to use its wholly-owned captive insurance company to insure or
reinsure part of all of the coverage shown in Section 12.5.
Such captive insurance company shall maintain capital and
surplus of at least One Hundred Million Dollars ($100,000,000)
throughout the period during which the captive insurance
company shall provide coverage to Phillips. Audited annual
reports for the captive insurance companies shall be provided
at the request of the Parties or of a Project Financing Entity
each year.
12.8.2 THE PARTNERSHIP'S CAPTIVE INSURER. The Partnership shall
have the right to use its wholly-owned captive insurance
company, if any, to insure or reinsure part of all of the
coverage shown in Section 12.1. Such captive insurance company
shall maintain capital and surplus of at least One Hundred
Million Dollars ($100,000,000) throughout the period during
which the captive insurance company shall provide coverage to
the Partnership. Audited annual reports for the captive
insurance companies shall be provided at the request of the
Parties or of a Project Financing Entity each year.
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13. INDEMNIFICATION
13.1 RELEASE AND INDEMNIFICATION BY THE PARTNERSHIP. Subject to the
limitation set forth in Section 13.4, the Partnership shall
release, indemnify, defend and hold Phillips, its Affiliates,
and each of their employees, directors and agents, harmless
from and against any and all damages, liabilities, expenses and
costs (including court costs and reasonable attorneys' fees) as
a result of any claims, demands, suits, causes of action,
proceedings or judgments for (a) any damage to or loss of
property (including the Project) of the Partnership, its
Affiliates, or any of the Partnership's partners (excluding
Phillips if it is a partner) or (b) any personal injury or
death to any of the employees, contractors, agents or Invitees
of the Partnership, its Affiliates, or any of the Partnership's
partners (excluding Phillips if it is a Partner); provided,
however, that such indemnity and release shall not apply to any
damage to land or water which is the subject of the
environmental indemnity provisions in the Ground Lease and
Easement Agreement.
13.2 RELEASE AND INDEMNIFICATION BY PHILLIPS. Subject to the
limitation set forth in Section 13.4, Phillips shall release,
indemnify, defend and hold the Partnership, its Affiliates, any
of the Partnership's partners and each of their employees,
directors and agents harmless from and against any and all
damages, liabilities, expenses and costs (including court costs
and reasonable attorneys' fees) as a result of any claims,
demands, suits, causes of action, proceedings or judgments for
(a) any damage to or loss of property (including HCC) of
Phillips or its Affiliates or (b) of any personal injury or
death to any of the employees, contractors, agents or Invitees
of Phillips or its Affiliates; provided, however, that such
indemnity and release shall not apply to any damage to land or
water which is the subject of the environmental indemnity
provisions in the Ground Lease and Easement Agreement.
13.3 COMPREHENSIVE CONSTRUCTION AND APPLICATION. THE PARTIES HEREBY
EXPRESS THEIR INTENT THAT THE RELEASES OF LIABILITY AND
INDEMNITIES CONTAINED IN SECTIONS 13.1 AND 13.2 ABOVE BE
LIBERALLY CONSTRUED. SUCH RELEASES OF LIABILITY AND INDEMNITIES
SHALL APPLY TO ANY LOSS, DAMAGE, DEFECT, PERSONAL INJURY OR
DEATH:
(A) WHICH ARISES FROM THE PERFORMANCE OF THE PROJECT
AGREEMENTS; AND
(B) WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF, INCLUDING,
WITHOUT LIMITATION, UNSEAWORTHINESS, STRICT LIABILITY,
BREACH OF WARRANTY (EXPRESS OR
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IMPLIED), IMPERFECTION OF MATERIALS, CONDITION OF ANY
PREMISES OR TRANSPORT TO OR FROM SUCH PREMISES, OR THE
NEGLIGENCE OF THE INDEMNITEE (OR RELEASED PARTY) OR ITS
EMPLOYEES, AGENTS AND INVITEES, WHETHER SUCH NEGLIGENCE BE
SOLE, JOINT OR CONCURRENT, ACTIVE OR PASSIVE; AND
(C) WHETHER THE CLAIM THEREFOR IS BASED ON COMMON LAW, CIVIL
LAW, MARITIME LAW, STATUTE OR CONTRACTUAL OBLIGATION
BETWEEN THE INDEMNITEE AND A THIRD PARTY.
13.4 LIMITATION ON INDEMNITIES. Notwithstanding anything to the
contrary contained herein, it is expressly agreed that
liability under the indemnities and releases contained in
Section 13.1 and 13.2 (including the obligation for attorneys'
fees and costs of defense) arising out of any single occurrence
which directly or indirectly results in coverage relating to
personal injury to or death of employees, agents, contractors,
their respective employees or Invitees, shall be limited to
Seven Million Five Hundred Thousand Dollars ($7,500,000). If in
the course of defense by either Party or any claims subject to
this Section 13.4, a Party believes its potential liability
under the indemnities set forth in Section 13.1 or 13.2, as
applicable, is likely to exceed the Seven Million Five Hundred
Thousand Dollar ($7,500,000) limitation, said Party shall have
the option of notifying the other Party that it will
unconditionally agree to pay the other Party the first Seven
Million Five Hundred Thousand Dollars ($7,500,000) of damages,
liabilities, expenses and costs (including but not limited to
court costs and attorneys' fees). The notifying Party shall
transfer the defense of all pending suits and claims subject to
this Section 13.4 to the other Party, and will cooperate in
arranging for an orderly transition in responsibility for
handling such suits and claims. The other Party shall, at its
option, be entitled to require that the notifying Party provide
security in a form satisfactory to the other Party to guarantee
payment of the Seven Million Five Hundred Thousand Dollars
($7,500,000) less any amount of damages, liabilities, expenses
and costs already incurred by the notifying Party (all of which
will be credited against this Seven Million Five Hundred
Thousand Dollar ($7,500,000) maximum payment under the
indemnities and releases contained in Sections 13.1 and 13.2).
To the extent any amount of damages, liabilities, expenses and
costs exceed the limitation set forth in this Section 13.4, the
Parties shall rely upon such rights and remedies as they may
have at law or in equity.
13.5 PROPERTY DAMAGE EXCLUSION. Notwithstanding the provisions of
Sections 13.1 and 13.2, each Party shall be liable to the
extent of its
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negligence for damage to the property of the other Party or its
Affiliates for the first One Hundred Thousand Dollars
($100,000) per occurrence.
13.6 MUTUAL INDEMNIFICATION FOR BREACH OF REPRESENTATIONS; FINES AND
PENALTIES.
13.6.1 PARTNERSHIP INDEMNIFICATION. The Partnership shall
indemnify, defend and hold Phillips, its Affiliates,
and each of their employees, directors and agents,
harmless from and against any and all (i) damages,
liabilities, expenses and costs (including court
costs and reasonable attorneys' fees) as a result of
any claims, demands, suits, causes of action,
proceedings or judgments arising as a result of the
breach of any of the representations and warranties
made by the Partnership herein, or (ii) any and all
fines or penalties (criminal or civil) or other
liabilities, expenses and costs (including court
costs and reasonable attorneys' fees) incurred or
paid as a result of any claims, demands, suits,
causes of action, proceedings or judgments made or
asserted by any Person against Phillips, its
Affiliates, or any of their employees, directors or
agents, for failure of the Partnership to comply with
any applicable Law or Permit related to the
performance of the obligations of the Partnership,
its Affiliates, or their employees, contractors or
agents, under the Project Agreements or arising out
of or otherwise related to the operation of the
Project; provided, however, that such indemnity shall
not apply to the extent that such fine, penalty or
other liability, expense or cost results from any
environmental matter which is the subject of the
environmental indemnity provisions in the Ground
Lease and Easement Agreement.
13.6.2 PHILLIPS INDEMNIFICATION. Phillips shall indemnify,
defend and hold the Partnership, its Affiliates, and
each of their employees, directors and agents,
harmless from and against any and all (i) damages,
liabilities, expenses and costs (including court
costs and reasonable attorneys' fees) as a result of
any claims, demands, suits, causes of action,
proceedings or judgments arising as a result of the
breach of any of the representations and warranties
made by Phillips herein, or (ii) any and all fines or
penalties (criminal or civil) or other liabilities,
expenses and costs (including court costs and
reasonable attorneys' fees) incurred or paid as a
result of any claims, demands, suits, causes of
action, proceedings or judgments made or asserted by
any Person against the Partnership, its Affiliates,
or any of their employees,
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directors or agents, for failure of Phillips to
comply with any applicable Law or Permit related to
the performance of the obligations of Phillips, its
Affiliates, or their employees or agents, under the
Project Agreements or arising out of or otherwise
related to the operation of HCC; provided, however,
that such indemnity shall not apply to the extent
that such fine, penalty or other liability, expense
or cost results from any environmental matter which
is the subject oF environmental indemnity provisions
in the Ground Lease and Easement Agreement.
13.7 EXCLUSIONS FROM RELEASES AND INDEMNITIES. Notwithstanding
anything to the contrary contained herein, the releases of
liabilities and indemnifications contained in Sections 13.1,
13.2 and 13.6 above and Section 2.7.3 of the Ground Lease and
Easement Agreement shall not apply to awards or assessment of
punitive damages and may not be relied upon by a Party to the
extent that any claim or liability was caused by the willful
misconduct of such Party.
13.8 NOTICE OF LEGAL DEFENSE. After receipt of notice of the
commencement of any legal action or claim against a Party as to
which the indemnities in this Section 13 may apply, the
indemnified Party shall provide reasonably prompt written
notice to the indemnifying Party; provided, however, that the
failure of the indemnified Party to provide such reasonably
prompt notice shall not relieve the indemnifying Party of any
obligations under this Section 13, but shall only reduce the
liability of the indemnifying Party by the amount of damages
attributable to the failure of the indemnified Party to give
such reasonably prompt notice. After receipt of such notice,
the indemnifying Party may, or if so requested by such
indemnified Party shall, assume the defense of such claim or
legal action without any reservation of rights and with counsel
reasonably satisfactory to the indemnified Party. The
indemnifying Party shall control the settlement of all claims
over which it has assumed defense; provided, however, that the
indemnifying Party shall not conclude any settlement which
requires any action or forbearance from action by the
indemnified Party or any of its Affiliates without the prior
written approval of the indemnified Party. In connection with
any such legal action or claim, when requested the indemnified
Party shall provide reasonable assistance, at the indemnifying
Party's expense, to the indemnifying Party. In all cases the
indemnified Party shall have the right to participate in and be
represented by counsel of its own choice and at its own expense
in any such legal action or claim.
13.9 APPLICATION OF INDEMNITIES. Except as specifically provided in
Sections 13.1, 13.2 and 13.6 above, the indemnities and
releases provided in this Section 13 shall be in addition to
and not in derogation
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or substitution of the releases or indemnifications provided
elsewhere in the Project Agreements.
13.10 SURVIVAL. The provisions of this Section 13 shall survive the
termination or expiration of the Project Agreements.
14. LIABILITY; NO DEDICATION
14.1 THIRD PARTIES. Except as otherwise expressly provided in
Section 13, nothing in this Agreement shall be construed to
create any duty to, standard of care with respect to, or any
liability to, any Person who is not a party to this Agreement.
14.2 NO DEDICATION. No undertaking by either Party under any
provision of this Agreement shall constitute the dedication of
that Party's electrical or transmission system, equipment or
facilities, or any portion thereof, to the other Party or to
the public, or affect the status of Phillips or of the
Partnership as an independent private entity and not a public
utility.
14.3 NO PARTNERSHIP. Nothing contained in this Agreement shall be
construed to create as between Phillips and the Partnership an
association, trust, partnership, joint venture, association
taxable as a corporation or other entity for the conduct of any
business for profit, or impose a trust or partnership duty,
obligation or liability or agency relationship on, or with
regard to, either Party. Each Party shall be individually and
severally liable for its own obligations under this Agreement.
14.4 NO CONSEQUENTIAL DAMAGES. The Parties agree that it is the
intent that notwithstanding anything to the contrary contained
in Section 14.5, neither Phillips nor the Partnership, nor
their respective officers, directors, partners, shareholders,
agents, employees, contractors or Affiliates, shall be liable
to the other Party or to its Affiliates, officers, directors,
shareholders, partners, agents, employees, successors or
assigns, for claims for incidental, special, indirect, punitive
or consequential damages of any nature connected with or
resulting from performance or non-performance of this
Agreement, including claims in the nature of lost revenue,
income or profits, irrespective of whether such claims are
based upon negligence, strict liability, contract, operation of
law or otherwise; provided, however, nothing in the foregoing
shall limit the obligation of a party to indemnify the other
party (the "Indemnitee") with respect to claims against the
Indemnitee under indemnities of the Indemnitee in favor of its
lenders and contractors to the extent such claims are otherwise
within the terms of Section 13.1 or Section 13.2 (as
applicable) hereof. Notwithstanding the foregoing, it is
specifically intended by the Parties that, subject to the duty
to mitigate,
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direct damages incurred as a result of a breach of the Project
Agreements, including payments, costs and expenses required
under the Project Agreements are not to be construed as
consequential damages or otherwise restricted hereunder.
14.5 INTENT. Except in cases of willful misconduct, the Parties
intend that the waivers and disclaimers of liability, releases
from liability, limitations and apportionments of liability,
and remedy provisions expressed throughout this Agreement shall
apply even in the event of the fault, negligence (in whole or
in part), strict liability or breach of contract of the Party
released or whose liability is waived, disclaimed, limited,
apportioned or fixed by such remedy provision, and shall extend
to such Party's Affiliates and to its and their partners,
shareholders, directors, officers, employees, contractors and
agents. The Parties also intend and agree that such provisions
shall continue in full force and effect notwithstanding the
termination, suspension, cancellation or rescission of this
Agreement, or of any other agreement entered into pursuant
hereto.
15. FORCE MAJEURE
15.1 EXCUSED PERFORMANCE. Each Party shall be excused from
performance hereunder and shall not be considered to be in
default or be liable in damages or otherwise with respect to
any obligation hereunder, except the obligation to pay money in
a timely manner for liabilities actually incurred, if and to
the extent that its failure of, or delay in, performance is due
to a Force Majeure Event; provided, that:
(a) Such Party gives the other Party written notice
describing the particulars of the Force Majeure Event,
including the expected duration, as soon as is reasonably
practicable, but in no event later than ten (10) days
after the occurrence of such event;
(b) The suspension of performance is of no greater scope
and of no longer duration than is reasonably required by
the Force Majeure Event;
(c) The Party affected by the Force Majeure Event uses its
Best Commercial Efforts to mitigate the effects thereof;
(d) No obligations of the Party which arose before the
occurrence causing the suspension of performance are
excused as a result of the occurrence; and
(e) When the Party is able to resume performance of its
obligations under this Agreement, such Party shall give
the other
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Party written notice to that effect and shall promptly
resume performance hereunder.
15.2 BURDEN OF PROOF. If the Parties are unable in good faith to
agree that a Force Majeure Event has occurred, the Parties
shall submit the dispute for resolution in accordance with the
Dispute Resolution Procedures, and the Party claiming a Force
Majeure Event shall have the burden of proof as to whether such
Force Majeure Event has occurred.
15.3 TERMINATION FOR FORCE MAJEURE.
15.3.1 RIGHT TO TERMINATE.
(a) Either Party may terminate this Agreement with
respect to the purchase and sale of Electrical Energy
upon thirty (30) days written notice if, following
the Commercial Operation Date, a Force Majeure Event
(other than as set forth in Section 15.3.2) hereunder
prevents either Party from substantial performance of
its obligations hereunder with respect to the
purchase and sale of Electrical Energy for a
continuous period of one (1) year.
(b) Either Party may terminate this Agreement with
respect to the purchase and sale of Steam upon thirty
(30) days written notice if, following the Commercial
Operation Date, a Force Majeure Event (other than as
set forth in Section 15.3.2) hereunder prevents
either Party from substantial performance of its
obligations hereunder with respect to the purchase
and sale of Steam for a continuous period of one (1)
year.
15.3.2 DESTRUCTION OR SUBSTANTIAL DAMAGE TO THE POWER PLANT
OR HCC AS THE FORCE MAJEURE EVENT. If destruction or
substantial damage to the Power Plant or HCC is a
Force Majeure Event hereunder, and a Party is
prevented from substantially performing its
obligations hereunder for a continuous period of two
(2) years, then either Party may terminate this
Agreement upon thirty (30) days written notice;
provided, however, if the Partnership does not
complete the rebuilding of the Power Plant as
required pursuant to Section 17.4 and elects to
terminate this Agreement pursuant to this Section
15.3.2, then the Partnership shall pay to Phillips
the Termination Fee, if applicable, pursuant to
Section 17.4.
15.3.3 MITIGATION PLAN. Notwithstanding the foregoing, this
Agreement shall not be terminated as set forth above
if the Party prevented from performing its
obligations is unable,
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despite the use of its Best Commercial Efforts, to
overcome the effects of such Force Majeure Event
during such one (1) or two (2) year period, as the
case may be, but nonetheless has demonstrated to the
reasonable satisfaction of the other Party that (a)
it is pursuing a plan approved by the other Party to
overcome the effects of the Force Majeure Event and
resume performance of its obligations hereunder, (b)
it is diligently applying its Best Commercial Efforts
to overcome the effects of the Force Majeure Event,
and (c) the Force Majeure Event can be overcome
within a reasonable time after the expiration of
either the one (1) or two (2) year period, as the
case may be.
16. EVENTS OF DEFAULT
16.1 DEFINITION. An Event of Default under this Agreement shall be
deemed to exist with respect to a Party upon the occurrence of
any one or more of the following events:
(a) Failure by a Party hereunder to make payment of any
amount due to the other Party under this Agreement, which
failure continues for a period of ten (10) days after
receipt of written notice of such nonpayment, unless such
amount is in dispute, in which case the Dispute Resolution
Procedures shall apply;
(b) Failure by a Party hereunder to perform fully any
other material obligation under this Agreement, if such
Party does not cure such failure within sixty (60) days of
the date of receipt of a notice from the other Party
demanding such cure (or within such longer period of time,
as is reasonably necessary to accomplish such cure, if it
cannot be reasonably accomplished within such sixty (60)
day period and such Party diligently commences such cure
in such period and continues such cure to completion);
(c) Failure by a Party hereunder to comply with the terms
of any final decision or order issued pursuant to the
Dispute Resolution Procedures, if such Party does not cure
such failure within sixty (60) days of the date of receipt
of a notice from the other Party demanding such cure (or
within such longer period of time, as is reasonably
necessary to accomplish such cure, if it cannot be
reasonably accomplished within such sixty (60) day period
and such Party diligently commences such cure in such
period and continues such cure to completion);
(d) If by order of a court of competent jurisdiction, a
receiver or liquidator or trustee of a Party or of any of
the property of a Party shall be appointed, and such
receiver or liquidator or trustee shall
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not have been discharged within a period of sixty (60)
days; or if by decree of such a court, a Party shall be
adjudicated bankrupt or insolvent or any substantial part
of the property of such Party shall have been sequestered,
and such decree shall have continued undischarged and
unstayed for a period of sixty (60) days after the entry
thereof; of if a petition to declare bankruptcy or to
reorganize a Party pursuant to any of the provisions of
the federal Bankruptcy Code, as it now exists or as it may
hereafter be amended, or pursuant to any other similar
state statute applicable to such Party, as now or
hereafter in effect, shall be filed against such Party and
shall not be dismissed within sixty (60) days after such
filing;
(e) If a Party shall file a voluntary petition in
bankruptcy under any provision of any federal or state
bankruptcy law or shall consent to the filing of any
bankruptcy or reorganization petition against it under any
similar law; or, without limitation of the generality of
the foregoing, if a Party shall file a petition or answer
or consent seeking relief or assisting in seeking relief
in a proceeding under any of the provisions of the federal
Bankruptcy Code, as it now exists or as it may hereafter
be amended, or pursuant to any other similar state statute
applicable to such Party, as now or hereafter in effect,
or an answer admitting the material allegations of a
petition filed against it in such a proceeding; or if a
Party shall make an assignment for the benefit of its
creditors; or if a Party shall admit in writing its
inability to pay its debts generally as they become due;
or if a Party shall consent to the appointment of a
receiver or receivers, or trustee or trustees, or
liquidator or liquidators of it or of all or any part of
its property; or
(f) If (i) Calpine shall directly or indirectly cease to
retain at least fifty percent (50%) of all general partner
interests in the Partnership, (ii) Calpine shall directly
or indirectly cease to retain at least twenty-five percent
(25%) of the overall ownership interests in the
Partnership, or (iii) the Partnership ceases to own one
hundred percent (100%) of the Project, in each case
without Phillips' consent, which consent shall not be
unreasonably withheld; provided, however, any foreclosure
by, or transfer in lieu of foreclosure to, any Project
Financing Entities may occur without Phillips' consent and
shall not constitute an Event of Default hereunder.
16.2 REMEDIES FOR DEFAULT. Subject to the provisions of Sections
14.4 and 14.5, upon the occurrence and during the continuation
of an Event of Default, the Party not in default shall have the
right to (a) terminate this Agreement with respect to either
the purchase and sale of Steam or
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Electrical Energy upon five (5) days written notice to the
other Party, or (b) terminate this Agreement in its entirety
upon five (5) days written notice to the other Party (which
notice may be given prior to the expiration of the cure periods
set forth in Section 16.1), in addition to the right to pursue
any remedy under this Agreement, or now or hereafter existing
under applicable Law or in equity; provided, however, that in
the case of an Event of Default with respect to the
Partnership, Phillips shall provide the Project Financing
Entities (a) with notice of such Event of Default and (b) the
opportunity to exercise the cure rights and such other rights,
remedies, acknowledgments, waivers and consents as may be
agreed to by Phillips in a Consent and Agreement in accordance
with the terms thereof.
16.3 REMEDIES NOT EXCLUSIVE. Except as otherwise expressly provided
to the contrary in the Project Agreements regarding the
Development Phase, the rights and remedies herein provided in
case of an Event of Default shall not be exclusive but shall,
to the extent permitted by Law, be cumulative and in addition
to all other rights and remedies existing at Law, in equity or
otherwise, except those rights and remedies which have been
waived or relinquished hereunder by the Parties pursuant to the
provisions of Sections 14.4 and 14.5. No delay or omission of a
Party to exercise any right or remedy accruing upon any Event
of Default shall impair any such right or remedy or constitute
a waiver of such default or an acquiescence therein. Every
right and remedy given by this Agreement or by Law to a Party
may be exercised from time to time, and as often as may be
deemed expedient, by such Party.
17. TERMINATION
17.1 TERMINATION DURING THE DEVELOPMENT PHASE. This Agreement shall
terminate in the event that either Party terminates the Project
Agreements during the Development Phase in accordance with
Section 4 of the Development and Construction Agreement.
17.2 TERMINATION FOR FAILURE TO ACHIEVE COMMERCIAL OPERATION.
Phillips shall have the right to terminate this Agreement upon
ten (10) days written notice of the Partnership in the event
the Commercial Operation Date has not occurred on or before
July 12, 2000, unless the Commercial Operation Date does not
occur on such date due to Phillips being in an Event of Default
or as a result of a Force Majeure Event, in which case the
termination date for such failure to achieve the Commercial
Operation Date shall be extended by one day for each day of
such Event of Default or such Force Majeure Event, as the case
may be, but shall not be extended for more than three hundred
sixty-five (365) days due solely to Force Majeure Events.
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17.3 TERMINATION FOR HCC SHUTDOWN. In the event of an HCC Shutdown,
either Party may terminate this Agreement upon thirty (30) days
written notice to the other Party; provided, however, the
Partnership shall continue to supply the residual electrical
energy requirements of HCC, if any, at the prices set forth in
this Agreement for the Variable Fuel Payment and Variable O&M
Payment, and the Electrical Capacity Payment shall be reduced
on a pro rata basis to the amount of electrical capacity being
reserved. Notwithstanding any such termination, the Fixed Steam
O&M Payment, the Fixed Steam Capacity Payment and the
Electrical Capacity Payment shall continue through the end of
the calendar year in which the HCC Shutdown occurs.
17.4 RIGHT TO TERMINATE FOR DESTRUCTION OR SUBSTANTIAL DAMAGE TO THE
POWER Plant. Notwithstanding anything to the contrary contained
herein, in the event the Power Plant is destroyed or
substantially damaged, then the Partnership shall be obligated
to rebuild the Power Plant as soon as possible thereafter such
that the Partnership shall be able to deliver Electrical Energy
and Steam to Phillips hereunder; provided, however, the
Partnership at its option, exercisable by written notice to
Phillips at any time within one hundred eighty (180) days after
the date of such damage or substantial destruction, may elect
not to rebuild the Power Plant and to terminate this Agreement
by paying to Phillips within fifteen (15) days after receipt
forty percent (40%) of each dollar of insurance proceeds
received by the Partnership up to a maximum of the Termination
Fee after first deducting all sums due to the Project Financing
Entities.
17.5 TERMINATION FOR FAILURE TO TAKE OFF-GAS. If Phillips terminates
the Facility Services Agreement because the Partnership was in
an Event of Default under the terms of the Facility Services
Agreement for failure to take Off-Gas, then Phillips may
terminate this Agreement by providing written notice to the
Partnership at any time within sixty (60) days after the
termination of the Facility Services Agreement.
17.6 TERMINATION OF GROUND LEASE AND EASEMENT AGREEMENT. In the
event the Ground Lease and Easement Agreement terminates, this
Agreement shall terminate.
17.7 TERMINATION IN THE EVENT OF FORECLOSURE. In the event of an
election by the Project Financing Entities under Section
13.3(ii) of the Ground Lease and Easement Agreement and the
Project Financing Entities do not assume, or cause a third
party (such third party being subject to the approval and
consent rights of Phillips as set forth in the Project
Agreements) to assume, all of the Partnership's obligations
under the Project Agreements arising after the acquisition date
within thirty (30)
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days of an acquisition (including foreclosure or transfer in
lieu of foreclosure) by the Project Financing Entities of (a)
the Project or the Partnership or any interests therein or (b)
the interests of a lessor in the Project or the Partnership (in
the event a financing lease or other similar financing
technique is used), then Phillips shall have the right to
immediately terminate this Agreement by delivery of written
notice thereof to the Project Financing Entities.
18. DISPUTE RESOLUTION
18.1 PROCEDURE. In the event a dispute arises between Phillips and
the Partnership regarding the application or interpretation of
any provision of this Agreement, the Parties agree to use the
procedures in this Section 18 to resolve any such disputes;
provided, however, that this Section shall not apply to
disputes relating in any manner to any indemnity, insurance or
release obligations under the Project Agreements.
18.2 INITIAL RESOLUTION ATTEMPTS. Either Party may initiate dispute
resolution procedures by sending written notice to the other
Party specifically stating the complaining Party's claim and
requesting dispute resolution in accordance with this Section
18. The receiving Party shall reply with the designation of a
person authorized to settle the dispute and shall list two (2)
alternative dates (both of which must be within ten (10)
Business Days after receipt of the complaint) for meeting at a
mutually agreeable location. If the matter has not been
resolved within ten (10) days of such meeting, each Party shall
refer the dispute to a senior executive of its organization who
shall meet at a mutually agreeable location within fourteen
(14) days to resolve the dispute.
18.3 ALTERNATIVE DISPUTE RESOLUTION. If the matter has not been
resolved within fourteen (14) days of the meeting of the senior
executives, the Parties will attempt in good faith to resolve
the dispute by employing a neutral mediator to attempt to
resolve the dispute in accordance with the CPR Model Procedure
for Mediation of Business Disputes; provided, however, that if
both Parties agree, the Parties can attempt to resolve the
dispute in accordance with the CPR Model Minitrial Procedure.
If the dispute has not been resolved pursuant to Section 18.2
within sixty (60) days of the commencement of such procedure,
the complaining Party may require the dispute to be settled by
arbitration.
18.4 ARBITRATION. All arbitration shall be in accordance with the
CPR Rules for Non-Administered Arbitration of Business Disputes
by three (3) arbitrators who shall be neutral, independent, and
generally knowledgeable about the type of transaction which
gave rise to the dispute. The arbitration shall be governed by
the United States
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Arbitration Act, 9 U.S.C. ss. 1-16; provided, however, that the
arbitrators shall include in their report/award a list of
findings, with supporting evidentiary references, upon which
they have relied in making their decision. The award rendered
by the arbitrators shall be final and binding upon the Parties
and judgment upon the award rendered by the arbitrators may be
entered by any court having jurisdiction thereof. The place of
arbitration shall be Houston, Texas.
18.5 GENERAL RULES AND PROVISIONS. Notwithstanding anything to the
contrary contained herein, and regardless of any procedures or
rules of the CPR, it is expressly agreed that the following
shall apply and control over any other provision in this
Section 18:
(a) Except to the extent that the Parties may agree upon
selection of one or more arbitrators, the CPR shall select
arbitrators from a panel reviewed by the Parties. Each
Party shall be entitled to exercise peremptory strikes
against one-third of the panel and may challenge other
candidates for lack of neutrality or lack of
qualification. Challenges shall be resolved in accordance
with the CPR rules.
(b) The Parties shall have at least twenty (20) days following
close of the arbitration hearing within which to submit a
brief (not to exceed eighteen (18) pages in length) and
ten (10) days from date of receipt of the opponent's brief
within which to respond thereto (response not to exceed
ten (10) pages in length).
(c) Arbitrators shall not award punitive damages or attorneys'
fees (except attorneys' fees specifically authorized in
the Project Agreements).
(d) The fees and expenses of the mediator and arbitrators
shall be shared equally by the Parties, and each Party
shall bear its own costs and expenses.
(e) The Parties may by written agreement (signed by both
Parties) alter any time deadline, location(s) for
meeting(s), or procedure outlined in this Section 18 or in
the CPR rules.
(f) Time is of the essence for purposes of the provisions of
this Section 18.
(g) Either Party may seek a restraining order, temporary
injunction, or other provisional judicial relief if the
Party in its sole judgment believes that such action is
necessary to avoid irreparable injury or to preserve the
status quo. The Parties will continue to participate
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<PAGE> 40
in good faith in the procedures despite any request for
provisional relief. Notwithstanding anything to the
contrary contained herein, in no event shall this Section
18.5(g) apply to Phillips' exercise of the Standby Boilers
Operating Rights, and the Partnership covenants and
agrees, and shall cause the Partners to covenant and
agree, not to seek a restraining order, temporary
injunction, or other provisional judicial relief with
respect to Phillips' exercise of the Standby Boilers
Operating Rights.
(h) The arbitrators shall have no authority, power or right to
alter, change, amend, modify, waive, add to or delete from
any of the provisions of the Project Agreements, and any
award rendered by the arbitrators shall be consistent with
the terms and conditions of the Project Agreements.
19. ASSIGNMENT
19.1 AGREEMENT BINDING. This Agreement shall be binding upon, and
shall inure to the benefit of, the Parties and their successors
and permitted assigns.
19.2 PERMITTED ASSIGNMENT. This Agreement shall not be assignable by
either Party without the prior written consent of the other
Party hereto, which consent shall not be unreasonably withheld
or delayed, except that this Agreement may be assigned (a) by
the Partnership without such consent (but with notice to
Phillips) to Project Financing Entities as security for the
obligations of the Partnership under any Project Financing
Agreement, and (b) by Phillips without such consent in
accordance with Section 19.3 below. Notwithstanding the
foregoing, Phillips shall have the absolute right to prohibit
assignment of this Agreement to competitors of Phillips'
business. Unless otherwise expressly agreed by the Parties, any
assignment of this Agreement shall not relieve the assigning
Party of any of its obligations under this Agreement. Except
with respect to the collateral assignment permitted under
clause (a) of this Section 19.2, no assignment by either Party
of this Agreement for any purpose whatsoever shall be valid
until all obligations of the assignor hereunder shall have been
assumed by the assignee by a written agreement delivered to the
other Party. Any assignment which does not comply with the
provisions of this Section 19.2 shall be null and void.
19.3 SALE OR ENCUMBRANCE BY PHILLIPS. Phillips shall have the right,
without the consent of the Partnership (but with notice to the
Partnership), to (a) sell, assign or otherwise transfer
ownership of all or any part of HCC to any Person, provided
such Person agrees in writing to be bound by
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<PAGE> 41
the terms and conditions of this Agreement and to assume
Phillips' obligations hereunder as they relate to the portion
of HCC acquired by such Person, and (b) mortgage or otherwise
encumber Phillips' interests in HCC, the Project Site, the
Easement Improvements or in the Project Agreements.
19.4 PROJECT FINANCING ENTITY DOCUMENTS. In connection with any
collateral assignment by the Partnership to a Project Financing
Entity as described in Section 19.2(a) above, Phillips agrees
to execute and deliver a Consent and Agreement in a form which
is reasonably acceptable to Phillips; provided, however,
Phillips shall not be obligated to agree to anything which
could impact the integrity and continued reliable and safe
operation of HCC. Phillips further agrees to furnish the
Project Financing Entity with such other documents as may be
reasonably requested. Notwithstanding the foregoing, Phillips
shall have no obligation to, and shall not be considered to be
in default for failure to, modify, alter or amend any of the
Project Agreements to accommodate any Person, including Project
Financing Entities.
19.5 ACQUISITION BY PROJECT FINANCING ENTITIES. In the event a
Project Financing Entity acquires (including by foreclosure or
transfer in lieu of foreclosure) all or any part of the
Project, then from and after such acquisition such Project
Financing Entity shall be bound by and agrees to assume the
obligations of the Partnership under the Project Agreements
which arise after the date of such acquisition.
20. REPRESENTATIONS AND WARRANTIES
Each Party hereby represents and warrants to the other Party that, as of
the Effective Date:
20.1 STANDING AND QUALIFICATION. Such Party is duly organized,
validly existing and in good standing under the laws of the
jurisdiction of its organization, is in good standing and is
qualified to do business in Texas and in all other
jurisdictions in which the nature of the business conducted by
it makes such qualification necessary and where failure so to
qualify would have a material adverse effect on its financial
condition, operations, prospects or business.
20.2 NO VIOLATION OF LAW; LITIGATION. Such Party (to its best
knowledge) is not in violation of any applicable Law
promulgated, or judgment entered by any federal, state, local
or other governmental authority which violations, individually
or in the aggregate, would adversely affect its performance of
any obligations under this Agreement. There are no legal or
arbitration proceedings or any proceeding by or before any
governmental or regulatory authority or agency, now pending or
(to its
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best knowledge) threatened against it which, if adversely
determined, could have a material adverse effect upon its
financial condition, operations, prospects or business, as a
whole, or its ability to perform under this Agreement.
20.3 LICENSES AND CONSENTS. Such Party (to its best knowledge) is
the holder of all Applicable Permits or other authorizations
required to permit it to operate or conduct its business now
and as contemplated by this Agreement, and, except for the
Applicable Permits and other approvals to be obtained by the
Parties pursuant to the Project Agreements, no authorization,
consent or approval of, notice to or filing with, any
governmental or regulatory authority is required for the
execution, delivery or performance by such Party of this
Agreement.
20.4 NO CONFLICT OR BREACH. To its best knowledge the execution,
delivery and performance by such Party of the Project
Agreement, the compliance with the terms and provisions hereof,
and the carrying out of the transactions contemplated hereby,
does not conflict or will not conflict with or result in a
breach or violation of any of the terms, conditions or
provisions of any Law, governmental rule or regulation or the
charter documents, as amended, or bylaws, as amended, of such
Party or any order, writ, injunction, judgment or decree of any
court or governmental authority against such Party or by which
it or any of its properties is bound, or any loan agreement,
indenture, mortgage, note, resolution, bond, or contract or
other agreement or instrument to which such Party is a party or
by which it or any of its properties is bound, or constitutes
or will constitute a default thereunder or will result in the
imposition of any lien upon any of its properties.
20.5 AUTHORITY. Such Party has all necessary power and authority to
execute, deliver and perform the Project Agreements and its
obligations hereunder; the execution, delivery and performance
of this Agreement has been duly authorized by all necessary
action on its part; it has duly and validly executed and
delivered this Agreement; and the Agreement constitutes a
legal, valid and binding obligation of such Party enforceable
against such Party in accordance with the terms hereof, except
as the enforceability thereof may be limited by bankruptcy,
insolvency, reorganization or moratorium or other similar laws
relating to the enforcement of creditors' rights generally and
by general equitable principles.
20.6 NO FEES. Such Party has not entered into any agreement,
arrangement or understanding with any Person which will result
in the obligation of the other Party, or any of its Affiliates,
to pay any finder's fee, brokerage commission or similar
payment in connection with this Agreement.
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<PAGE> 43
21. NOTICES
21.1 WRITING. Any notice, demand, offer or other written instrument
required or permitted to be given pursuant to this Agreement
shall be in writing signed by the Party giving such notice and
shall, to the extent reasonably practicable, be sent by telefax
(confirmed by a mailed or courier copy received within five (5)
days), and if not reasonably practicable to send by telefax,
then by hand delivery, overnight courier, telegram or
registered or certified mail, return receipt requested, to the
other Party at such address as set forth below.
If delivered to Phillips:
Phillips Chemical Company, a Division of Phillips Petroleum
Company
1400 Jefferson, Pasadena, TX 77501
Attention: HCC General Manager
Telephone: 713-475-3610
Telefax: 713-475-3589
With a copy to:
Phillips Chemical Company, a Division of Phillips Petroleum
Company
2625 Bay Area Boulevard
Houston (Clear Lake) TX 77058
Attention: ATTN: Plastics Finance Manager
Telephone: 713-244-3076
Telefax: 713-244-3005
If delivered to the Partnership:
Pasadena Cogeneration L.P.
50 West San Fernando
San Jose, California 95113
Attention: Asset Manager and General Counsel
Telephone: (408) 995-5115
Telefax: (408) 995-0505
With a copy to:
Calpine Pasadena Cogeneration, Inc.
Project Office Address as provided by
Calpine Pasadena Cogeneration, Inc.
Pasadena, TX
Attention: Plant Manager
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<PAGE> 44
Each Party shall have the right to change the place to which
notice shall be sent or delivered or to specify one additional
address to which copies of notices may be sent, in either case by
similar notice sent or delivered in like manner to the other
Party.
21.2 TIMING OF RECEIPT. Without limiting any other means by which a
Party may be able to prove that a notice has been received by
the other Party, a notice shall be deemed to be duly received:
(a) If delivered by hand, overnight courier or telegram, on
the date when received at the address of the recipient;
(b) If sent by registered or certified mail, on the date of
the return receipt; or
(c) If sent by telefax, upon receipt by the sender of an
acknowledgment or transmission report generated by the
machine from which the telefax was sent indicating that
the telefax was sent in its entirety and received at the
recipient's telefax number.
22. MISCELLANEOUS
22.1 AMENDMENTS. No change, amendment or modification of this
Agreement shall be valid or binding upon the Parties unless
such change, amendment or modification shall be in writing and
duly executed by both Parties.
22.2 CAPTIONS. The captions contained in this Agreement are for
convenience and reference only and in no way define, describe,
extend or limit the scope or intent of this Agreement or the
intent of any provision contained herein.
22.3 SEVERABILITY. The invalidity of one or more phrases, sentences,
clauses or Sections contained in this Agreement shall not
affect the validity of the remaining portions of this Agreement
so long as the material purposes of this Agreement can be
determined and effectuated.
22.4 NO WAIVER. Any failure of either Party to enforce any of the
provisions of this Agreement or to require compliance with any
of its terms at any time during the pendency of this Agreement,
shall in no way affect the validity of this Agreement, or any
part hereof, and shall not be deemed a waiver of the right of
such Party thereafter to enforce any and each such provision.
Any consent or approval given pursuant to this Agreement shall
be limited to its express terms and shall not otherwise
increase the
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<PAGE> 45
obligations of the Party giving such consent or approval or
otherwise reduce the obligations of the Party receiving such
consent or approval.
22.5 FURTHER ASSURANCES. Each Party agrees to execute and deliver
all further instruments and documents, and take any further
action that may be reasonably necessary, to effectuate the
purposes and intent of this Agreement.
22.6 ESTOPPEL CERTIFICATES. Each Party shall, from time to time,
upon fifteen (15) days prior request by the other Party,
execute, acknowledge and deliver to the requesting Party a
certificate signed by an authorized officer of such Party
stating that this Agreement is unmodified and in full force and
effect (or, if there have been modifications, that such
Agreement is in full force and effect as modified, and setting
forth such modifications) and either stating that to the
knowledge of the signer of such certificate no Event of Default
exists hereunder or thereunder or specifying each such Event of
Default to which the signer has knowledge. Any certificate
given pursuant to this Section 22.6 may be relied upon by the
Project Financing Entity and by any prospective mortgagee or
purchaser of any interest in this Agreement, the Power Plant,
or any other portion of the Project.
22.7 CONFIDENTIALITY. During the Term of this Agreement, it may
become necessary or desirable, from time to time, for either
Party to provide or disclose to the other Party information
that is either confidential or proprietary (which shall not
include information already known to such other Party or
generally known or available to the public). The Labeling Party
may orally request such information to be kept confidential if
such information is not in a written format, and in such case
shall identify and confirm such confidential information in
writing to the other Party no later than fifteen (15) days
after such disclosure. If the confidential or proprietary
information is in a written format, the Labeling Party shall
label such information as either confidential or proprietary.
The other Party shall not reproduce, copy, use or disclose
(except when required by governmental authorities or by Law)
any such information in whole or in part to a third party for
any purpose without the consent of the Labeling Party. The
other Party shall restrict the internal disclosure of any such
confidential or proprietary information to only those
employees, officers and directors who have a "need to know"
such information, and shall restrict those individuals from
disclosing, using or permitting the disclosure of such
information. In disclosing confidential or proprietary
information to governmental authorities, the disclosing Party
shall cooperate with the Labeling Party to minimize the amount
of such information furnished. At the specific request of the
Labeling Party , the disclosing Party shall endeavor to secure
the agreement of such
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<PAGE> 46
governmental authorities to maintain specified portions of such
information in confidence. In the case of any disclosure of any
such confidential or proprietary information, whether or not
such disclosure is permitted by this Section 22.7, the
disclosing Party shall promptly give written notice thereof to
the Labeling Party.
22.8 LIMITATION ON PHOTOS AND VIDEOS AT HCC. The Partnership, its
Affiliates, and each of their employees, directors, agents and
Invitees, shall not take any photographs, films, videos or
similar visual depictions of any part of HCC without Phillips'
prior written approval.
22.9 RECORDS AND AUDIT. Each Party shall, and shall procure that its
contractors shall, maintain a true and correct set of records
pertaining to all activities relating to its performance of
this Agreement and all transactions related thereto. Each Party
further agrees, and shall procure that its contractors agree,
to retain all such records for a period of not less than two
(2) years after the termination of this Agreement. Any
representative or representatives authorized by a Party may
audit any and all such records of the other Party or its
contractors at any time or times during the Term of this
Agreement and during the two (2) year period following its
termination. The foregoing obligations in this Section 22.9
shall survive the termination, expiration or mutual
cancellation of this Agreement.
22.10 CONFLICT OF INTEREST. The Partnership shall not, and shall
procure that its contractors shall not, pay any commissions,
fees or grant any rebates to any employee, officer or agent of
Phillips nor favor employees, officers or agents of Phillips
with gifts or entertainment of significant cost or value, nor
enter into any business arrangement with employees, officers or
agents of Phillips other than as a representative of Phillips,
without Phillips' written approval. Compliance with this
Section 22.10 is subject to audit under Section 22.9 above.
22.11 NO LIABILITY. Except as otherwise expressly provided in this
Agreement, no Affiliate of any Party, nor the officers,
directors, employees or agents of such Affiliate of any Party,
shall have any liability to the other Party in connection with
this Agreement; provided, however, this Section 22.11 shall not
be construed to limit liability of any such Affiliate or Person
under any other agreement.
22.12 APPLICABLE LAW. This Agreement shall be governed by, construed
and enforced in accordance with the laws of the State of Texas,
including with respect to matters of construction, validity and
performance, without giving effect to any choice of law rules
that may direct the application of the laws of another
jurisdiction.
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<PAGE> 47
22.13 VENUE AND SUBMISSION TO JURISDICTION. THE VENUE FOR ANY LEGAL
ACTION TO ENFORCE, INTERPRET OR OTHERWISE LITIGATE DISPUTES
RELATING TO THIS AGREEMENT SHALL BE HOUSTON, TEXAS, AND EACH
PARTY HERETO HEREBY SUBMITS TO THE NON-EXCLUSIVE JURISDICTION
OF THE FEDERAL AND STATE COURTS OF THE STATE OF TEXAS LOCATED
IN HOUSTON, TEXAS. EACH PARTY HEREBY IRREVOCABLY WAIVES, TO THE
FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH IT MAY NOW
OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUCH PROCEEDING
BROUGHT IN ANY SUCH COURT AND ANY CLAIM THAT ANY SUCH
PROCEEDING HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. THE
PREVAILING PARTY IN ANY SUCH ACTION SHALL BE ENTITLED TO
RECOVER FROM THE OTHER PARTY REASONABLE ATTORNEYS' FEES AND
COSTS.
22.14 COUNTERPARTS. This Agreement may be signed in any number of
counterparts and each counterpart shall represent a fully
executed original as if signed by both Parties.
22.15 SURVIVAL. Notwithstanding any provision of this Agreement to
the contrary, expiration or other termination of this Agreement
shall not relieve the Parties of obligations that by their
nature should survive such expiration or termination, including
remedies in the case of a termination for an Event of Default,
promises of indemnity, payment obligations, confidentiality,
audit rights, and dispute resolution provisions.
23. INCORPORATION OF PROVISIONS
Notwithstanding anything to the contrary contained herein, Philips shall
have the rights set forth in Sections 13 and 14 (titled Project Financing
Agreements and Electric Utility Agreements) of the Ground Lease and Easement
Agreement and such provisions are incorporated herein and made a part hereof by
this reference and shall apply as though fully set forth herein.
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<PAGE> 48
IN WITNESS WHEREOF, Phillips and the Partnership have caused this
Agreement to be executed by their duly authorized representatives as of December
16, 1996.
PHILLIPS PETROLEUM COMPANY
By:
------------------------------------
Name:
------------------------------------
Title:
------------------------------------
PASADENA COGENERATION L.P.
By: Calpine Pasadena Cogeneration, Inc., its
General Partner
By:
------------------------------------
Name:
------------------------------------
Title:
------------------------------------
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<PAGE> 49
EXHIBIT A
TO THE AMENDED AND RESTATED ENERGY SALES AGREEMENT
ELECTRICAL ENERGY PRICING
VARIABLE FUEL PAYMENT = Actual Power Usage1/ (kWH/Billing Period) x Variable
Fuel Component
VARIABLE FUEL COMPONENT (1995 basis) = $0.01119/kWH x Fuel Gas Escalator
VARIABLE O&M PAYMENT = Actual Power Usage1/ (kWH/Billing Period) x Variable O&M
Component; provided, however, during the first COD Year, as a one time
adjustment, a reduction of Five Hundred Thousand Dollars ($500,000) shall be
made during the first COD Year by reducing the Variable O&M Payments by
$41,666.67 each month during the first COD Year.
VARIABLE O&M COMPONENT (1995 basis) = $0.00649/kWH x the O&M Escalator.
FIRM ELECTRICAL CAPACITY PAYMENT = for 80 MVA, $5,518,187 per annum, paid
quarterly.
INTERRUPTIBLE ELECTRICAL CAPACITY PAYMENT = 10 MVA of Interruptible Electrical
Capacity at $3,550 per MVA-month x the MVA determined pursuant to Section 2.4.2
of the Energy Sales Agreement, paid quarterly, for up to 10 MVA.
PAYMENT FOR USE OF EXCESS ELECTRICAL ENERGY required pursuant to Section 2.3.3 =
(a) $5.75 per kVA-month for a Billing Period if the electrical capacity of the
Project has not been fully committed at the time of such demand, or (b) $17.25
per kVA-month for such Billing Period at any time after the electrical capacity
of the Project is fully committed.
OPTION TO ADJUST: if the number of MW supplied hereunder is reduced as a result
of Phillips' exercise of the Option to Adjust pursuant to Section 2.8, the Firm
Electrical Capacity Payment shall be reduced by $68,977.33 for each annual
megawatt, of Firm Electrical Capacity no longer supplied by the Partnership.
All Escalators and results of calculations shall be rounded up or down, as
appropriate, to 3 decimal places (1.0333 to 1.033, 1.0335 to 1.034).
1/ "ACTUAL POWER USAGE" shall mean the actual kWH/hours delivered to Phillips
from the Partnership during a Billing Period.
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<PAGE> 50
<TABLE>
<CAPTION>
Payment Payment
Electricity Period Terms
- ------------------------------------- -------------- ------------------------------
<S> <C> <C>
Variable O&M Payment Monthly o (See Section 5.3)
Variable Fuel Payment Monthly o (See Section 5.3)
Firm Capacity Payment Quarterly o end of quarter in arrears
(See Section 5.3)
Interruptible Capacity Payment Quarterly o end of quarter in arrears
(See Section 5.3)
</TABLE>
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<PAGE> 51
EXHIBIT B
TO THE AMENDED AND RESTATED ENERGY SALES AGREEMENT
STEAM PRICING
VARIABLE STEAM PAYMENT = Actual Steam Usage 1/ (klbs/month) x Variable Steam
Component
VARIABLE STEAM COMPONENT (1995 basis) = $2.259/klb 2/ x Fuel Gas Escalator
FIXED STEAM CAPACITY PAYMENT = for up to the Maximum Steam Requirement
$2,000,000 per annum, paid quarterly.
FIXED STEAM O&M PAYMENT (1995 basis) = $1,155,000 per annum x the O&M Escalator,
paid quarterly.
<TABLE>
<CAPTION>
Steam Payment Period Payment Terms
- -------------------------------------------------------------------------------
<S> <C> <C>
Variable Steam Payment Monthly (See Section 5.3)
Fixed Steam O&M Payment Quarterly end of quarter in
arrears (See Section 5.3)
Fixed Steam Capacity Payment Quarterly end of quarter in
arrears (See Section 5.3)
</TABLE>
All Escalators and results of calculations shall be rounded up or down, as
appropriate, to 3 decimal places (1.0333 to 1.033, 1.0335 to 1.034).
1/ "ACTUAL STEAM USAGE" shall mean the actual pounds of Steam delivered to
Phillips from the Partnership during a Billing Period.
2/ For low pressure (50-90 psig) process steam, this amount shall be
$2.220/klb.
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<PAGE> 52
EXHIBIT C
TO THE AMENDED AND RESTATED ENERGY SALES AGREEMENT
STEAM SPECIFICATIONS
1) INTERMEDIATE PRESSURE PROCESS STEAM
PRESSURE 335 PSIG
TEMPERATURE SATURATED
TOTAL SOLIDS Less Than 0.05 PPM
SODIUM Less Than 0.02 PPM
SILICA Less Than 0.02 PPM
(1) Steady state operations within HCC require the steam pressure
variation be limited to +/- 10 psi.
(2) The Project must be capable of responding to an instantaneous
change in 335 psig steam demand of 60,000 lbs/hr without
pressure degradation or excursions exceeding 15 psig from the
regulated 335 psig steam header pressure within HCC at the
Point of Delivery for Steam.
2) LOW PRESSURE PROCESS STEAM
PRESSURE 50 - 90 PSIG
TEMPERATURE 310(Degree) - 340(Degree)F
TOTAL SOLIDS Less Than 0.05 PM
SODIUM Less Than 0.02 PPM
SILICA Less Than 0.02 PPM
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<PAGE> 53
EXHIBIT D
TO THE AMENDED AND RESTATED ENERGY SALES AGREEMENT
CONDENSATE RETURN SPECIFICATIONS
PRESSURE 50 to 60 PSIG (depending on location)
TEMPERATURE 240 DEG F
pH 8.5
Conductivity Less Than 20 MHO/CM
AMOUNT RETURNED approximately 50%
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<PAGE> 54
AMENDED AND RESTATED
ENERGY SALES AGREEMENT
BETWEEN
PHILLIPS PETROLEUM COMPANY
AND
PASADENA COGENERATION L.P.
DATED AS OF DECEMBER 16, 1996
THE PASADENA COGENERATION PROJECT
<PAGE> 55
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
1. DEFINITIONS AND INTERPRETATION.....................................................1
1.1 Definitions...............................................................1
1.2 Construction of Terms.....................................................2
1.3 Drafting Interpretations..................................................2
1.4 Documents Included........................................................2
1.5 Conflicting Provisions....................................................2
1.6 Entire Agreement..........................................................2
2. PURCHASE AND SALE OF ELECTRICAL ENERGY AND ELECTRICAL CAPACITY.....................2
2.1 Exclusive Source..........................................................2
2.2 Purchase and Sale Obligation for Electric Energy and
Electrical Capacity.................................................3
2.2.1 Purchase and Sale Obligation for Electrical
Energy.....................................................3
2.2.2 Purchase and Sale Obligation for Electrical
Capacity...................................................3
2.3 Electrical Payment........................................................3
2.3.1 Variable Fuel Payment and Variable O&M Payment................4
2.3.2 Electrical Capacity Payment...................................4
2.3.2.1 Commencement of Firm Electrical
Capacity Payments...................................4
2.3.2.2 Adjustments to Electrical Capacity
Payments............................................4
2.3.3 Payment for Use of Excess Electrical Energy...................5
2.4 Interruptible Capacity....................................................5
2.4.1 Scheduling Interruptible Capacity.............................5
2.4.2 MW Calculation................................................5
2.5 Standby Electrical Agreement..............................................5
2.5.1 Standby Agreement.............................................6
2.5.2 Payment Adjustment............................................6
2.6 Payment Adjustment for Failure to Supply..................................6
2.6.1 Payment Adjustment...........................................6
2.6.2 Reimbursement for Incremental Cost...........................6
2.7 Additional Electrical Energy..............................................7
2.8 Option to Adjust Purchase of Electrical Energy and
Electrical Capacity.................................................7
2.8.1 Pricing Notice................................................7
2.8.2 Right of First Refusal........................................7
</TABLE>
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<PAGE> 56
<TABLE>
<S> <C>
2.8.3 Adjustment Terms..............................................8
3. PURCHASE AND SALE OF STEAM AND STEAM CAPACITY......................................9
3.1 Exclusive Source..........................................................9
3.2 Purchase and Sale Obligation for Steam and Steam Capacity.................9
3.2.1 Purchase and Sale Obligation..................................9
3.2.2 Purchase and Sale Obligation for Steam Capacity...............9
3.3 Characteristics of Steam.................................................10
3.4 Steam Payment............................................................10
3.4.1 Variable Steam Payment.......................................10
3.4.2 Fixed Steam O&M Payment......................................10
3.4.3 Fixed Steam Capacity Payment.................................10
3.5 Additional Steam Requirement.............................................10
4. CONDENSATE RETURN.................................................................10
4.1 Transportation of Steam and Condensate...................................10
4.2 Condensate Return........................................................11
4.3 Failure to Supply Condensate.............................................11
4.4 Operation of the Standby Boilers due to Phillips' Failure
to Supply Raw Water and Condensate.................................11
4.5 Interruption of Water Supply.............................................12
5. BILLING AND PAYMENT...............................................................12
5.1 Monthly Billing Cycle for Steam, Electrical Energy and
Standby............................................................12
5.2 Quarterly Payment for Capacity and Fixed Steam O&M.......................12
5.3 Payment of Invoices......................................................13
5.4 Interest.................................................................13
6. OPERATION OF THE PROJECT..........................................................13
6.1 Operation of the Project.................................................13
6.2 Operating and Communication Guidelines...................................14
6.3 Steam Redundancy Requirements............................................14
6.4 Standby Boilers Operating Rights.........................................14
6.4.1 Exercise of Rights...........................................14
6.4.2 Partnership Cooperation......................................15
6.4.3 Partnership Fuel Gas.........................................15
6.4.4 Remedies and Liabilities.....................................15
6.4.5 Reimbursement for Costs and Expenses.........................15
6.4.6 Cessation of Standby Boiler Operating Rights ...............16
6.4.7 Training.....................................................16
6.5 Phillips Representative..................................................16
</TABLE>
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<PAGE> 57
<TABLE>
<S> <C>
6.6 The Partnership Representative...........................................16
6.7 Obligation to Provide Auxiliary Boilers..................................17
7. MAINTENANCE AND REPAIR OF THE PROJECT.............................................17
7.1 The Partnership's Maintenance Obligations................................17
7.2 Phillips' Maintenance Obligations........................................18
7.3 Scheduled Maintenance for the Power Plant and HCC........................18
7.4 Inspection and Observation Rights........................................19
8. METERING..........................................................................19
8.1 Metering Devices.........................................................19
8.2 Periodic Inspection......................................................19
8.3 Retroactive Adjustments..................................................20
8.4 Access to Metering Devices...............................................20
9. REVIEW MEETINGS...................................................................20
10. SALES TO THIRD PARTY PURCHASERS..................................................20
11. TERM OF AGREEMENT................................................................21
11.1 Term 21
11.2 Renewal Term............................................................21
11.3 Phillips Extension Term.................................................21
12. INSURANCE........................................................................21
12.1 Insurance Coverages.....................................................22
12.1.1 Workers' Compensation Insurance.............................22
12.1.2 Commercial General Liability Insurance......................22
12.1.3 Automobile Liability Insurance..............................22
12.1.4 Excess/Umbrella Liability Insurance.........................22
12.2 Endorsements............................................................23
12.2.1 Waiver of Subrogation.......................................23
12.2.2 Severability................................................23
12.2.3 Primary Coverage............................................23
12.2.4 Additional Insured..........................................23
12.3 All-Risk Property Insurance.............................................24
12.3.1 Builder's All-Risk Insurance and All-Risk
Property and Boiler and Machinery Insurance...............24
12.3.2 Waiver of Subrogation.......................................24
12.4 Contractors and Subcontractors..........................................24
12.5 Phillips Insurance Coverages............................................25
12.5.1 Workers' Compensation Insurance.............................25
12.5.2 Commercial General Liability Insurance......................25
12.5.3 Automobile Liability Insurance..............................25
12.5.4 Excess/Umbrella Liability Insurance.........................25
</TABLE>
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<TABLE>
<S> <C>
12.5.5 Property Insurance..........................................25
12.6 Evidence of Insurance...................................................26
12.7 Disclaimer..............................................................26
12.8 Placement of Insurance Coverage with Captive............................26
12.8.1 Phillips' Captive Insurer...................................26
12.8.2 The Partnership's Captive Insurer...........................26
13. INDEMNIFICATION..................................................................27
13.1 Release and Indemnification by the Partnership..........................27
13.2 Release and Indemnification by Phillips.................................27
13.3 COMPREHENSIVE CONSTRUCTION AND APPLICATION..............................27
13.4 Limitation on Indemnities...............................................28
13.5 Property Damage Exclusion...............................................28
13.6 Mutual Indemnification for Breach of Representations;
Fines and Penalties................................................29
13.6.1 Partnership Indemnification.................................29
13.6.2 Phillips Indemnification....................................29
13.7 Exclusions from Releases and Indemnities................................30
13.8 Notice of Legal Defense.................................................30
13.9 Application of Indemnities..............................................30
13.10 Survival...............................................................31
14. LIABILITY; NO DEDICATION.........................................................31
14.1 Third Parties...........................................................31
14.2 No Dedication...........................................................31
14.3 No Partnership..........................................................31
14.4 No Consequential Damages................................................31
14.5 Intent..................................................................32
15. FORCE MAJEURE....................................................................32
15.1 Excused Performance.....................................................32
15.2 Burden of Proof.........................................................33
15.3 Termination for Force Majeure...........................................33
15.3.1 Right to Terminate..........................................33
15.3.2 Destruction or Substantial Damage to the Power
Plant or HCC as the Force Majeure Event...................33
15.3.3 Mitigation Plan.............................................33
16. EVENTS OF DEFAULT................................................................34
16.1 Definition..............................................................34
16.2 Remedies for Default....................................................35
16.3 Remedies Not Exclusive..................................................36
</TABLE>
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17. TERMINATION......................................................................36
17.1 Termination During the Development Phase................................36
17.2 Termination for Failure to Achieve Commercial Operation.................36
17.3 Termination for HCC Shutdown............................................36
17.4 Right to Terminate for Destruction or Substantial Damage
to the Power Plant.................................................37
17.5 Termination for Failure to Take Off-Gas.................................37
17.6 Termination of Ground Lease and Easement Agreement......................37
17.7 Termination in the Event of Foreclosure.................................37
18. DISPUTE RESOLUTION...............................................................38
18.1 Procedure...............................................................38
18.2 Initial Resolution Attempts.............................................38
18.3 Alternative Dispute Resolution..........................................38
18.4 Arbitration.............................................................38
18.5 General Rules and Provisions............................................39
19. ASSIGNMENT.......................................................................40
19.1 Agreement Binding.......................................................40
19.2 Permitted Assignment....................................................40
19.3 Sale or Encumbrance by Phillips.........................................40
19.4 Project Financing Entity Documents......................................41
19.5 Acquisition by Project Financing Entities...............................41
20. REPRESENTATIONS AND WARRANTIES...................................................41
20.1 Standing and Qualification..............................................41
20.2 No Violation of Law; Litigation.........................................41
20.3 Licenses and Consents...................................................42
20.4 No Conflict or Breach...................................................42
20.5 Authority...............................................................42
20.6 No Fees.................................................................42
21. NOTICES..........................................................................42
21.1 Writing.................................................................42
21.2 Timing of Receipt.......................................................44
22. MISCELLANEOUS....................................................................44
22.1 Amendments..............................................................44
22.2 Captions................................................................44
22.3 Severability............................................................44
22.4 No Waiver...............................................................44
22.5 Further Assurances......................................................44
22.6 Estoppel Certificates...................................................45
</TABLE>
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22.7 Confidentiality.........................................................45
22.8 Limitation on Photos and Videos at HCC..................................46
22.9 Records and Audit.......................................................46
22.10 Conflict of Interest...................................................46
22.11 No Liability...........................................................46
22.12 Applicable Law.........................................................46
22.13 Venue and Submission to Jurisdiction...................................46
22.14 Counterparts...........................................................47
22.15 Survival...............................................................47
23. INCORPORATION OF PROVISIONS......................................................47
</TABLE>
APPENDICES
APPENDIX A Definitions
EXHIBITS
EXHIBIT A Electrical Energy Pricing
EXHIBIT B Steam Pricing
EXHIBIT C Steam Specifications
EXHIBIT D Condensate Return Specifications
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<ARTICLE> 5
<LEGEND>
The schedule contains summary financial information extracted from Calpine
Corporation's Consolidated Balance Sheet as of December 31, 1996 and from the
Consolidated Statement of Operations for the twelve months ended December 31,
1996 and is qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<EXCHANGE-RATE> 1
<CASH> 100,010
<SECURITIES> 5,470
<RECEIVABLES> 42,788
<ALLOWANCES> 0
<INVENTORY> 3,262
<CURRENT-ASSETS> 171,187
<PP&E> 750,727
<DEPRECIATION> 100,674
<TOTAL-ASSETS> 1,030,215
<CURRENT-LIABILITIES> 74,969
<BONDS> 563,640
0
0
<COMMON> 20
<OTHER-SE> 203,107
<TOTAL-LIABILITY-AND-EQUITY> 1,030,215
<SALES> 199,464
<TOTAL-REVENUES> 214,554
<CGS> 121,800
<TOTAL-COSTS> 129,200
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 45,294
<INCOME-PRETAX> 27,756
<INCOME-TAX> 9,064
<INCOME-CONTINUING> 18,692
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 18,692
<EPS-PRIMARY> 1.27
<EPS-DILUTED> 1.24
</TABLE>
