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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [NO FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
COMMISSION FILE NUMBER 033-73160
CALPINE CORPORATION
(A DELAWARE CORPORATION)
I.R.S. EMPLOYER IDENTIFICATION NO. 77-0212977
50 WEST SAN FERNANDO STREET
SAN JOSE, CALIFORNIA 95113
TELEPHONE: (408) 995-5115
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
CALPINE CORPORATION COMMON STOCK, $0.001 PAR VALUE REGISTERED ON THE NEW YORK
STOCK EXCHANGE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE.
Indicate by check mark whether the Registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of the Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates of the
Registrant as of February 16, 1999: $626.6 million. Common stock outstanding as
of February 16, 1999: 20,253,797
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 1999 Annual
Meeting of Shareholders: ....................Part III (Items 10, 11 and 12)
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FORM 10-K
ANNUAL REPORT
FOR THE YEAR ENDED DECEMBER 31, 1998
TABLE OF CONTENTS
PART I
PAGE
----
Item 1. Business.................................................... 2
Item 2. Properties.................................................. 27
Item 3. Legal Proceedings........................................... 28
Item 4. Submission of Matters To A Vote of Security Holders......... 29
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 29
Item 6. Selected Financial Data..................................... 29
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 29
Item 7a. Quantitative Qualitative Disclosure......................... 29
Item 8. Financial Statements and Supplementary Data................. 29
Item 9. Changes in and Disagreements with Accountants and Financial
Disclosure................................................ 29
PART III
Item 10. Executive Officers, Directors and Key Employees............. 29
Item 11. Executive Compensation...................................... 29
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 29
Item 13. Certain Relationships and Related Transactions.............. 29
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 29
Signatures............................................................ 34
Index to Consolidated Financial Statements and Schedules.............. F-1
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ITEM 1. BUSINESS
Except for historical financial information contained herein, the matters
discussed in this annual report may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding the intent, belief or current
expectations of the Company and its management. Prospective investors are
cautioned that any such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties; actual results
could differ materially from those indicated by such forward-looking statements.
Among the important factors that could cause actual results to differ materially
from those indicated by such forward-looking statements are: (i) that the
information is of a preliminary nature and may be subject to further adjustment,
(ii) those risks and uncertainties identified under "Risk Factors" included in
Item 1. Business in this Annual Report on Form 10-K, (iii) the possible
unavailability of financing, (iv) risks related to the development, acquisition
and operation of power plants, (v) the impact of avoided cost pricing, energy
price fluctuations and gas price increases, (vi) the impact of curtailment,
(vii) the seasonal nature of the Company's business, (viii) start-up risks, (ix)
general operating risks, (x) the dependence on third parties, (xi) risks
associated with international investments, (xii) risks associated with the power
marketing business, (xiii) changes in government regulation, (xiv) the
availability of natural gas, (xv) the effects of competition, (xvi) the
dependence on senior management, (xvii) volatility in the Company's stock price,
(xviii) fluctuations in quarterly results and seasonality, and (xix) other risks
identified from time to time in the Company's reports and registration
statements filed with the Securities and Exchange Commission.
OVERVIEW
Calpine is a leading independent power company engaged in the development,
acquisition, ownership and operation of power generation facilities and the sale
of electricity predominantly in the United States. We have experienced
significant growth in all aspects of our business over the last five years.
Currently, we own interests in 22 power plants having an aggregate capacity of
2,729 megawatts and have three acquisition transactions pending in which we will
acquire 14 geothermal power plants with an aggregate capacity of 694 megawatts
and certain related steam fields. We also have six gas-fired projects under
construction having an aggregate capacity of 1,784 megawatts and have announced
plans to develop four gas-fired power plants with a total capacity of 2,580
megawatts. Upon completion of pending acquisitions and projects under
construction, we will have interests in 40 power plants having an aggregate
capacity of 5,207 megawatts, of which we will have a net interest in 4,271
megawatts. This represents significant growth from the 342 megawatts of capacity
we had at the end of 1993. Of this total generating capacity, 81% will be
attributable to gas-fired facilities and 19% will be attributable to geothermal
facilities.
As a result of our expansion program, our revenues, cash flow, earnings and
assets have grown significantly over the last five years, as shown in the table
below.
COMPOUND ANNUAL
1993 1998 GROWTH RATE
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(DOLLARS IN MILLIONS)
Total Revenue................................... $ 69.9 $ 555.9 51%
EBITDA.......................................... 42.4 255.3 43%
Net Income...................................... 3.8 45.7 64%
Total Assets.................................... 302.3 1,728.9 42%
Since our inception in 1984, we have developed substantial expertise in all
aspects of the development, acquisition and operation of power generation
facilities. We believe that the vertical integration of our extensive
engineering, construction management, operations, fuel management and financing
capabilities provides us with a competitive advantage to successfully implement
our acquisition and development program and has contributed to our significant
growth over the past five years.
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THE MARKET
The power industry represents the third largest industry in the United
States, with an estimated end-user market of over $250 billion of electricity
sales in 1998 produced by an aggregate base of power generation facilities with
a capacity of approximately 750,000 megawatts. In response to increasing
customer demand for access to low-cost electricity and enhanced services, new
regulatory initiatives have been and are continuing to be adopted at both the
state and federal level to increase competition in the domestic power generation
industry. The power generation industry historically has been largely
characterized by electric utility monopolies producing electricity from old,
inefficient, high-cost generating facilities selling to a captive customer base.
Industry trends and regulatory initiatives have transformed the existing market
into a more competitive market where end users purchase electricity from a
variety of suppliers, including non-utility generators, power marketers, public
utilities and others.
There is a significant need for additional power generating capacity
throughout the United States, both to satisfy increasing demand, as well as to
replace old and inefficient generating facilities. Due to environmental and
economic considerations, we believe this new capacity will be provided
predominantly by gas-fired facilities. We believe that these market trends will
create substantial opportunities for efficient, low-cost power producers that
can produce and sell energy to customers at competitive rates.
In addition, as a result of a variety of factors, including deregulation of
the power generation market, utilities, independent power producers and
industrial companies are disposing of power generation facilities. To date,
numerous utilities have sold or announced their intentions to sell their power
generation facilities and have focused their resources on the transmission and
distribution segments. Many independent producers operating a limited number of
power plants are also seeking to dispose of their plants in response to
competitive pressures, and industrial companies are selling their power plants
to redeploy capital in their core businesses.
STRATEGY
Our strategy is to continue our rapid growth by capitalizing on the
significant opportunities in the power market, primarily through our active
development and acquisition programs. In pursuing our proven growth strategy, we
utilize our extensive management and technical expertise to implement a fully
integrated approach to the acquisition, development and operation of power
generation facilities. This approach uses our expertise in design, engineering,
procurement, finance, construction management, fuel and resource acquisition,
operations and power marketing, which we believe provides us with a competitive
advantage. The key elements of our strategy are as follows:
- Development and expansion of power plants. We are actively pursuing the
development and expansion of highly efficient, low-cost, gas-fired power
plants to replace old and inefficient generating facilities and meet the
demand for new generation. Our strategy is to develop power plants in
strategic geographic locations that enable us to utilize existing power
generation assets and operate the power plants as integrated electric
generation systems. This allows us to achieve significant operating
synergies and efficiencies in fuel procurement, power marketing and
operations and maintenance.
In July 1998, we achieved a key milestone in our development program by
completing the development of our 240 megawatt gas-fired power plant in
Pasadena, Texas. The Pasadena Power Plant serves as a prototype for
future development projects. We currently have six gas-fired projects
under construction, representing an additional 1,784 megawatts of
capacity. Of these new projects, we are expanding our Pasadena and Clear
Lake facilities by an aggregate of 545 megawatts. In addition, four new
gas-fired power plants, with a total capacity of 1,239 megawatts, are
currently under construction in Dighton, Massachusetts; Tiverton, Rhode
Island; Rumford, Maine; and Westbrook, Maine. We have also announced
plans to develop four additional power generation facilities, totaling an
estimated 2,580 megawatts of electricity, in California, Texas and
Arizona.
- Acquisition of power plants. Our strategy is to acquire power generating
facilities that meet our stringent criteria, provide significant
potential for revenue, cash flow and earnings growth and provide
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the opportunity to enhance the operating efficiencies of the plants. We
have significantly expanded and diversified our project portfolio through
the acquisition of power generation facilities through the completion of
23 acquisitions to date.
We are currently in the process of completing three acquisitions
comprising 14 geothermal power plants with an aggregate capacity of 694
megawatts and certain related steam fields located in The Geysers,
California. Historically, we have served as the steam supplier for these
facilities, which have been owned and operated by PG&E. We anticipate that
these acquisitions will enable us to consolidate our operations in The
Geysers into a single ownership structure and to integrate the power plant
and steam field operations, allowing us to optimize the efficiency and
performance of the facilities. We believe that these acquisitions will
provide us with significant synergies that utilize our expertise in
geothermal power generation and position us to benefit from the demand for
"green" energy in the competitive market.
- Enhancement of the performance and efficiency of existing power
projects. We continually seek to maximize the power generation potential
of our operating assets and minimize our operating and maintenance
expenses and fuel costs. This will become even more significant as our
portfolio of power generation facilities expands to an aggregate of 40
power plants with an aggregate capacity of 5,207 megawatts, after
completion of our pending acquisitions and projects currently under
construction. We focus on operating our plants as an integrated system of
power generation, which enables us to minimize costs and maximize
operating efficiencies. As of December 31, 1998, our power generation
facilities have operated at an average availability of approximately
96.5%. We believe that achieving and maintaining a low-cost of production
will be increasingly important to compete effectively in the power
generation market.
DESCRIPTION OF FACILITIES
We currently have interests in 22 power generation facilities and three
steam fields with a current aggregate capacity of approximately 3,018 megawatts,
consisting of 18 gas-fired power plants with a total capacity of 2,602
megawatts, four geothermal power generation facilities with a total capacity of
127 megawatts, and three steam fields with a total capacity of 289 megawatts. We
also have three pending acquisitions of 14 geothermal power plants with an
aggregate capacity of 694 megawatts and certain related steam fields, six
gas-fired projects currently under construction with an aggregate capacity of
1,784 megawatts, and have announced the development of four additional power
plants with an aggregate capacity of 2,580 megawatts. Each of the power
generation facilities currently in operation produces electricity for sale to a
utility or other third-party end user. Thermal energy produced by the gas-fired
cogeneration facilities is sold to governmental and industrial users.
The gas-fired and geothermal power generation projects in which we have an
interest produce electricity and thermal energy that are typically sold pursuant
to long-term power sales agreements. 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.
Upon completion of the pending acquisitions and projects under
construction, we will provide operating and maintenance services for 31 of the
40 power plants and steam fields in which we have an interest. Such services
include the operation of power plants, geothermal steam fields, wells and well
pumps, gathering systems and gas pipelines. We also supervise maintenance,
materials purchasing and inventory control, manage cash flow, train staff and
prepare operating and maintenance manuals for each power generation facility
that we operate. As a facility develops an operating history, we analyze its
operation and may modify or upgrade equipment or adjust operating procedures or
maintenance measures to enhance the facility's
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reliability or profitability. These services are performed under the terms of an
operating and maintenance agreement pursuant to which we are generally
reimbursed for certain costs, paid an annual operating fee and may also be paid
an incentive fee based on the performance of the facility. The fees payable to
us are generally subordinated to any lease payments or debt service obligations
of non-recourse financing for the project.
In order to provide fuel for the gas-fired power generation facilities in
which we have an interest, natural gas reserves are acquired or natural gas is
purchased from third parties under supply agreements. We attempt to structure a
gas-fired power facility's fuel supply agreement so that gas costs have a direct
relationship to the fuel component of revenue energy payments. We currently hold
interests in geothermal leaseholds in The Geysers that produce steam that is
supplied to the power generation facilities owned by us for use in producing
electricity.
Certain power generation facilities in which we have an interest have been
financed primarily with non-recourse project financing that is structured to be
serviced out of the cash flows derived from the sale of electricity, thermal
energy and/or steam produced by such facilities and provides that the
obligations to pay interest and principal on the loans are secured almost solely
by the capital stock or partnership interests, physical assets, contracts and/or
cash flow attributable to the entities that own the facilities. The lenders
under non-recourse project financing generally have no recourse for repayment
against us or any of our assets or the assets of 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 we have an
interest are located on sites which are leased on a long-term basis. See
"-- Properties."
MEGAWATTS
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# OF PLANT CALPINE NET
PLANTS CAPACITY INTEREST
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In operation............................................... 22 2,729 2,065
Pending acquisitions....................................... 14 694 694
Under construction
-- New facilities........................................ 4 1,239 967
-- Expansion projects.................................... -- 545 545
Announced development...................................... 4 2,580 2,140
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44 7,787 6,411
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Set forth below is certain information regarding our operating power
plants, plants under construction, pending power plant acquisitions and
development projects.
POWER NAMEPLATE CALPINE CALPINE NET
GENERATION CAPACITY INTEREST INTEREST
POWER PLANT TECHNOLOGY LOCATION (MEGAWATTS)(1) PERCENTAGE (MEGAWATTS)
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OPERATING POWER PLANTS
Texas City........................ Gas-Fired Texas 450.0 100% 450.0
Clear Lake........................ Gas-Fired Texas 377.0 100% 377.0
Pasadena.......................... Gas-Fired Texas 240.0 100% 240.0
Gordonsville...................... Gas-Fired Virginia 240.0 50% 120.0
Lockport.......................... Gas-Fired New York 184.0 11.4% 20.9
Bayonne........................... Gas-Fired New Jersey 165.0 7.5% 12.4
Auburndale........................ Gas-Fired Florida 150.0 50% 75.0
Sumas(2).......................... Gas-Fired Washington 125.0 70% 87.5
King City......................... Gas-Fired California 120.0 100% 120.0
Gilroy............................ Gas-Fired California 120.0 100% 120.0
Kennedy International Airport..... Gas-Fired New York 107.0 50% 53.5
Pittsburg......................... Gas-Fired California 70.0 100% 70.0
Sonoma............................ Geothermal California 60.0 100% 60.0
Bethpage.......................... Gas-Fired New York 57.0 100% 57.0
Greenleaf 1....................... Gas-Fired California 49.5 100% 49.5
Greenleaf 2....................... Gas-Fired California 49.5 100% 49.5
Stony Brook....................... Gas-Fired New York 40.0 50% 20.0
Agnews............................ Gas-Fired California 29.0 20% 5.8
Watsonville....................... Gas-Fired California 28.5 100% 28.5
West Ford Flat.................... Geothermal California 27.0 100% 27.0
Bear Canyon....................... Geothermal California 20.0 100% 20.0
Aidlin............................ Geothermal California 20.0 5% 1.0
PENDING ACQUISITIONS
Sonoma County (12 power plants)... Geothermal California 544.0 100% 544.0
Lake County (2 power plants)...... Geothermal California 150.0 100% 150.0
PROJECTS UNDER CONSTRUCTION
Westbrook......................... Gas-Fired Maine 540.0 100% 540.0
Pasadena Expansion................ Gas-Fired Texas 510.0 100% 510.0
Tiverton(3)....................... Gas-Fired Rhode Island 265.0 62.8% 166.4
Rumford(4)........................ Gas-Fired Maine 265.0 66.7% 176.8
Dighton(5)........................ Gas-Fired Massachusetts 169.0 50% 84.5
Clear Lake Expansion.............. Gas-Fired Texas 35.0 100% 35.0
ANNOUNCED DEVELOPMENT
Delta Energy Center............... Gas-Fired California 880.0 50% 440.0
Magic Valley...................... Gas-Fired Texas 700.0 100% 700.0
South Point....................... Gas-Fired Arizona 500.0 100% 500.0
Sutter............................ Gas-Fired California 500.0 100% 500.0
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(1) Nameplate capacity may not represent the actual output for a facility at any
particular time.
(2) See "-- Operating Power Plants -- Sumas Power Plant" for a description of
our interest in the Sumas Power Plant. Based on our current estimates, these
payments represent approximately 70% of distributable cash.
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(3) See "Project Development and Acquisitions -- Project Development -- Projects
Under Construction -- Tiverton Power Plant" for a description of our
interest in the Tiverton Power Plant.
(4) See "Project Development and Acquisitions -- Project Development -- Projects
Under Construction -- Rumford Power Plant" for a description of our interest
in the Rumford Power Plant.
(5) See "Project Development and Acquisitions -- Project Development -- Projects
Under Construction -- Dighton Power Plant" for a description of our interest
in the Dighton Power Plant. Based on our current estimates, our interest
represents our right to receive approximately 50% of project cash flow
beginning at the commencement of commercial operation.
OPERATING POWER PLANTS
Texas City Power Plant. The Texas City Power Plant is a 450 megawatt
gas-fired cogeneration facility located in Texas City, Texas. Electricity
generated by the Texas City Power Plant is sold under two separate long-term
agreements to (1) Texas Utilities Electric Company ("TUEC") under a power sales
agreement terminating on September 30, 2002, and (2) Union Carbide Corporation
("UCC") under a steam and electricity services agreement terminating on June 30,
1999. Each agreement contains payment provisions for capacity and electric
energy payments. Under a steam and electricity services agreement expiring
October 19, 2003, the Texas City Power Plant will supply UCC with 300,000 lbs/hr
of steam on a monthly average basis, with the required supply of steam not
exceeding 600,000 lbs/hr at any given time. During 1998, the Texas City Power
Plant generated approximately 2,517,316,000 kilowatt hours of electric energy
for sale to TUEC and UCC and approximately $188.3 million of revenue.
Clear Lake Power Plant. The Clear Lake Power Plant is a 377 megawatt
gas/hydrogen-fired cogeneration facility located in Pasadena, Texas. Electricity
generated by the Clear Lake Power Plant is sold under three separate long-term
agreements to (1) Texas-New Mexico Power Company ("TNP") under a power sales
agreement terminating in 2004, (2) Houston Lighting and Power Company ("HL&P")
under a power sales agreement terminating in 2005, and (3) Hoechst Celanese
Chemical Group, Inc. ("HCCG") under a power sales agreement terminating in 2004.
Each power sales agreement contains payment provisions for capacity and energy
payments. Under a steam purchase and sale agreement expiring August 31, 2004,
the Clear Lake Power Plant will supply up to 900,000 lbs/hr of steam to HCCG.
During 1998, the Clear Lake Power Plant generated approximately 2,912,649,000
kilowatt hours of electric energy for sale to TNP, HL&P and HCCG and
approximately $89.3 million of revenue.
Pasadena Power Plant. The Pasadena Power Plant is a 240 megawatt gas-fired
cogeneration facility located in Pasadena, Texas. Electricity generated by the
Pasadena Power Plant is sold under contract and into the open market. We entered
into an energy sales agreement with Phillips Petroleum Company ("Phillips")
terminating in 2018. Under this agreement, we provide 90 megawatts of
electricity and 200,000 lbs/hr of steam to Phillips' Houston Chemical Complex.
West Texas Utilities purchased 50 megawatts of capacity through the end of 1998.
In 1999, LG&E Energy Marketing will purchase up to 150 megawatts of electricity
under a one-year agreement. TUEC is also under contract to purchase up to 150
megawatts of electricity under a two-year agreement beginning December 1, 1999.
The remaining available electricity output is sold into the competitive market
through our power marketing organization. During 1998, the Pasadena Power Plant
generated approximately 812,314,000 kilowatt hours of electric energy with
approximately $30.5 million of revenue.
Gordonsville Power Plant. The Gordonsville Power Plant is a 240 megawatt
gas-fired cogeneration facility located near Gordonsville, Virginia. Electricity
generated by the Gordonsville Power Plant is sold to the Virginia Electric and
Power Company under two power sales agreements terminating on June 1, 2024, each
of which include payment provisions for capacity and energy. The Gordonsville
Power Plant sells steam to Rapidan Service Authority under the terms of a steam
purchase and sales agreement, which expires June 1, 2004. During 1998, the
Gordonsville Power Plant generated approximately 213,382,000 kilowatt hours of
electrical energy and approximately $37.4 million of revenue.
Lockport Power Plant. The Lockport Power Plant is a 184 megawatt gas-fired,
combined-cycle cogeneration facility located in Lockport, New York. The facility
is owned and operated by Lockport Energy
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Associates, L.P. ("LEA"). We own an indirect 11.36% limited partnership interest
in LEA. Electricity and steam is sold to General Motors Corporation ("GM") under
an energy sales agreement expiring in December 2007 for use at the GM Harrison
plant, which is located on a site adjacent to the Lockport Power Plant.
Electricity is also sold to New York State Electricity and Gas Company ("NYSEG")
under a power purchase agreement expiring October 2007. NYSEG is required to
purchase all of the electric power produced by the Lockport Power Plant not
required by GM. For 1998, the Lockport Power Plant generated approximately
1,284,830,000 kilowatt hours of electricity and had $118.6 million in revenue.
Bayonne Power Plant. The Bayonne Power Plant is a 165 megawatt gas-fired
cogeneration facility located in Bayonne, New Jersey. The facility is primarily
owned by an affiliate of Cogen Technologies, Inc. We own an indirect 7.5%
limited partnership interest in the facility. Electricity generated by the
Bayonne Power Plant is sold under various power sales agreements to Jersey
Central Power & Light Company and Public Service Electric and Gas Company of New
Jersey. The Bayonne Power Plant also sells steam to two industrial entities.
During 1998, the Bayonne Power Plant generated approximately 1,399,860,000
kilowatt hours of electrical energy and approximately $116.6 million in revenue.
Auburndale Power Plant. The Auburndale Power Plant is a 150 megawatt
gas-fired cogeneration facility located near the city of Auburndale, Florida.
Electricity generated by the Auburndale Power Plant is sold under various power
sales agreements to Florida Power Corporation ("FPC"), Enron Power Marketing and
Sonat Power Marketing. Auburndale sells 131.18 megawatts of capacity and energy
to FPC under three power sales agreements, each terminating at the end of 2013.
The Auburndale Power Plant sells steam under two steam purchase and sale
agreements. One agreement is with Cutrale Citrus Juices, USA, an affiliate of
Sucocitro Cutrale LTDA, expiring on July 1, 2014. The second agreement is with
Todhunter International, Inc., doing business as Florida Distillers Company,
expiring on July 1, 2009. During 1998, the Auburndale Power Plant generated
approximately 1,022,146,000 kilowatt hours of electrical energy and
approximately $49.6 million in revenue.
Sumas Power Plant. The Sumas Power Plant is a 125 megawatt gas-fired,
combined cycle cogeneration facility located in Sumas, Washington. We currently
hold an ownership interest in the Sumas Power Plant, which entitles us to
receive certain scheduled distributions during the next two years. Upon receipt
of the scheduled distributions, we will no longer have any ownership interest in
the Sumas Power Plant. Electrical energy generated by the Sumas Power Plant is
sold to Puget Sound Power & Light Company ("Puget") under the terms of a 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. In
addition to the sale of electricity to Puget, pursuant to a long-term steam
supply and dry kiln lease agreement, the Sumas Power Plant produces and sells
approximately 23,000 lbs/hr of low pressure steam to an adjacent lumber-drying
facility owned by Sumas, which has been leased to and is operated by Socco, Inc.
During 1998, the Sumas Power Plant generated approximately 915,227,280 kilowatt
hours of electrical energy and approximately $49.6 million of total revenue.
King City Power Plant. The King City Power Plant is a 120 megawatt
gas-fired, combined-cycle cogeneration facility located in King City,
California. We operate the King City Power Plant under a long-term operating
lease for this facility with BAF Energy ("BAF"), terminating in 2018.
Electricity generated by the King City Power Plant is sold to Pacific Gas and
Electric Company ("PG&E") under a power sales agreement terminating in 2019. The
power sales agreement contains payment provisions for capacity and energy. 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., an
affiliate of BAF, under a long-term contract coterminous with the power sales
agreement. During 1998, the King City Power Plant generated approximately
428,825,000 kilowatt hours of electrical energy and approximately $45.6 million
of total revenue.
Gilroy Power Plant. The Gilroy Power Plant is a 120 megawatt gas-fired
cogeneration facility located in Gilroy, California. Electricity generated by
the Gilroy Power Plant is sold to PG&E under a power sales agreement terminating
in 2018. In addition, the Gilroy Power Plant produces and sells thermal energy
to a thermal host, Gilroy Foods, Inc., under a long-term contract that is
coterminous with the power sales
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agreement. During 1998, the Gilroy Power Plant generated approximately
477,628,000 kilowatt hours of electrical energy for sale to PG&E and
approximately $39.3 million in revenue.
Kennedy International Airport Power Plant. The Kennedy International
Airport Power Plant is a 107 megawatt gas-fired cogeneration facility located at
John F. Kennedy International Airport in Queens, New York. The facility is owned
and operated by KIAC Partners ("KIAC"). We own an indirect 50% general
partnership interest in KIAC. Electricity and thermal energy generated by the
Kennedy International Airport Power Plant is sold to the Port Authority, and
incremental electric power is sold to Consolidated Edison Company of New York,
the New York Power Authority and other utility customers. Electric power and
chilled and hot water generated by the Kennedy International Airport Power Plant
is sold to the Port Authority under an energy purchase agreement that expires
November 2015. The Port Authority has a minimum thermal take requirement in an
amount sufficient to maintain the Kennedy International Airport Power Plant's QF
status. For 1998, the Kennedy International Airport Power Plant generated
approximately 533,755,000 kilowatt hours of electrical energy, 266,252 mmbtu of
chilled water and 178,405 mmbtu of hot water for sale to the Port Authority, and
generated approximately $56.1 million in revenue.
Pittsburg Power Plant. The Pittsburg Power Plant is a 70 megawatt gas-fired
cogeneration facility, located at The Dow Chemical Company's ("Dow") Pittsburg,
California chemical facility. We sell up to 18 megawatts of electricity to Dow
under a power sales agreement expiring in 2008. Surplus energy is sold to PG&E
under an existing power sales agreement. In addition, we sell approximately
200,000 lbs/hr of steam to Dow under an energy sales agreement expiring in 2003
and to USS-POSCO Industries' nearby steel mill under a process steam contract
expiring in 2001. From its acquisition, in July 1998, through the end of 1998,
the Pittsburg Power Plant generated approximately 92,358,000 kilowatt hours of
electrical energy to Dow and PG&E and approximately $9.4 million in revenue.
Sonoma Power Plant. The Sonoma Power Plant consists of a 60 megawatt
geothermal power plant and associated steam fields located in Sonoma County,
California. Electricity generated by the Sonoma Power Plant is sold to the
Sacramento Municipal Utility District ("SMUD") under a 50 megawatt agreement
terminating in 2001. In addition, SMUD has the option to purchase 10 megawatts
of peak power production through 2005. We market the excess electricity into the
California power market. From its acquisition, in June 1998, through the end of
1998, the Sonoma Power Plant generated approximately 215,433,000 kilowatt hours
of electrical energy and approximately $6.2 million in revenue.
Bethpage Power Plant. The Bethpage Power Plant is a 57 megawatt gas-fired,
combined cycle cogeneration facility located adjacent to a Northrup Grumman
Corporation ("Grumman") facility in Bethpage, New York. Electricity and steam
generated by the Bethpage Power Plant are sold to Grumman under an energy
purchase agreement expiring August 2004. Electric power not sold to Grumman is
sold to Long Island Power Authority ("LIPA") under a generation agreement also
expiring August 2004. Grumman is also obligated to purchase a minimum of 158,000
klbs of steam per year from the Bethpage Power Plant. For 1998, the Bethpage
Power Plant generated approximately 474,991,000 kilowatt hours of electrical
energy for sale to Grumman and LIPA and approximately $32.9 million in revenue.
Greenleaf 1 Power Plant. The Greenleaf 1 Power Plant is a 49.5 megawatt
gas-fired cogeneration facility located near Yuba City, California. We operate
this facility under an operating lease with Union Bank of California,
terminating in 2014 (the "Greenleaf Lease"). Electricity generated by the
Greenleaf 1 Power Plant is sold to PG&E under a power sales agreement
terminating in 2019 which contains payment provisions for capacity and energy.
In addition, 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
us. For 1998, the Greenleaf 1 Power Plant generated approximately 326,543,000
kilowatt hours of electrical energy for sale to PG&E and approximately $17.8
million in revenue.
Greenleaf 2 Power Plant. The Greenleaf 2 Power Plant is a 49.5 megawatt
gas-fired cogeneration facility located near Yuba City, California. This
facility is also operated by us under the Greenleaf Lease. Electricity generated
by the Greenleaf 2 Power Plant is sold to PG&E under a power sales agreement
terminating in 2019 which includes payment provisions for capacity and energy.
In addition to the sale of electricity to PG&E, the Greenleaf 2 Power Plant
sells thermal energy to Sunsweet Growers, Inc. pursuant to a 30-year contract.
For
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1998, the Greenleaf 2 Power Plant generated approximately 377,101,000 kilowatt
hours of electrical energy for sale to PG&E and approximately $20.3 million in
revenue.
Stony Brook Power Plant. The Stony Brook Power Plant is a 40 megawatt
gas-fired cogeneration facility located on the campus of the State University of
New York at Stony Brook, New York ("SUNY"). The facility is owned by Nissequogue
Cogen Partners ("NCP"). We own an indirect 50% general partner interest in NCP.
Steam and electric power is sold to SUNY under an energy supply agreement
expiring in 2023. Under the energy supply agreement, SUNY is required to
purchase, and the Stony Brook Power Plant is required to provide, all of SUNY's
electric power and steam requirements up to 36.125 megawatts of electricity and
280,000 lbs/hr of process steam. The remaining electricity is sold to LIPA under
a long-term agreement. LIPA is obligated to purchase electric power generated by
the facility not required by SUNY. SUNY is required to purchase a minimum of
402,000 klbs per year of steam. For 1998, the Stony Brook Power Plant generated
approximately 326,584,000 kilowatt hours of electrical energy and 1,185,000 klbs
of steam for sale to SUNY and LIPA and approximately $31.1 million in revenue.
Agnews Power Plant. The Agnews Power Plant is a 29 megawatt gas-fired,
combined-cycle cogeneration facility located on the East Campus of the
state-owned Agnews Developmental Center in San Jose, California. We hold 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. Electricity
generated by the Agnews Power Plant is sold to PG&E under a power sales
agreement terminating in 2021 which contains payment provisions for capacity and
energy. In addition, the Agnews Power Plant produces and sells electricity and
approximately 7,000 lbs/hr of steam to the Agnews Developmental Center pursuant
to a 30-year energy service agreement. During 1998, the Agnews Power Plant
generated approximately 215,180,000 kilowatt hours of electrical energy and
total revenue of $11.7 million.
Watsonville Power Plant. The Watsonville Power Plant is a 28.5 megawatt
gas-fired, combined cycle cogeneration facility located in Watsonville,
California. We operate the Watsonville Power Plant under an operating lease with
the Ford Motor Credit Company, terminating in 2009. Electricity generated by the
Watsonville Power Plant is sold to PG&E under a power sales agreement
terminating in 2009 which contains payment provisions for capacity and energy.
During 1998, the Watsonville Power Plant produced and sold steam to Farmers
Processing, a food processor. In addition, the Watsonville Power Plant sold
process water produced from its water distillation facility to Farmer's Cold
Storage, Farmer's Processing and Cascade Properties. For 1998, the Watsonville
Power Plant generated approximately 206,007,000 kilowatt hours of electrical
energy for sale to PG&E and approximately $11.4 million in revenue.
West Ford Flat Power Plant. The West Ford Flat Power Plant consists of a 27
megawatt geothermal power plant and associated steam fields located in northern
California. Electricity generated by the West Ford Flat Power Plant is sold to
PG&E under a power sales agreement terminating in 2008 which contains payment
provisions for capacity and energy. During 1998, the West Ford Flat Power Plant
generated approximately 235,529,000 kilowatt hours of electrical energy for sale
to PG&E and approximately $34.6 million of revenue.
Bear Canyon Power Plant. The Bear Canyon Power Plant consists of a 20
megawatt geothermal power plant and associated steam fields located in northern
California, two miles south of the West Ford Flat Power Plant. Electricity
generated by the Bear Canyon Power Plant is sold to PG&E under two 10 megawatt
power sales agreements terminating in 2008 which contain payment provisions for
capacity and energy. During 1998, the Bear Canyon Power Plant generated
approximately 176,508,000 kilowatt hours of electrical energy and approximately
$20.4 million of revenue.
Aidlin Power Plant. The Aidlin Power Plant consists of a 20 megawatt
geothermal power plant and associated steam fields located in northern
California. We hold an indirect 5% ownership interest in the Aidlin Power Plant.
Electricity generated by the Aidlin Power Plant is sold to PG&E under two 10
megawatt power sales agreements terminating in 2009 which contain payment
provisions for capacity and energy. During 1998, the Aidlin Power Plant
generated approximately 170,046,000 kilowatt hours of electrical energy and
revenue of $24.4 million.
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PROJECT DEVELOPMENT AND ACQUISITIONS
We are actively engaged in the development and acquisition of power
generation projects. We have historically focused principally on the development
and acquisition of interests in gas-fired and geothermal power projects,
although we also consider projects that utilize other power generation
technologies. We have significant expertise in a variety of power generation
technologies and have substantial capabilities in each aspect of the development
and acquisition process, including design, engineering, procurement,
construction management, fuel and resource acquisition and management, financing
and operations.
ACQUISITIONS
We will consider the acquisition of an interest in operating projects as
well as projects under development where we would assume responsibility for
completing the development of the project. In the acquisition of power
generation facilities, we generally seek to acquire an ownership interest in
facilities that offer us attractive opportunities for revenue and earnings
growth, and that permit us to assume sole responsibility for the operation and
maintenance of the facility. In evaluating and selecting a project for
acquisition, we consider a variety of factors, including the type of power
generation technology utilized, the location of the project, the terms of any
existing power or thermal energy sales agreements, gas supply and transportation
agreements and wheeling agreements, the quantity and quality of any geothermal
or other natural resource involved, and the actual condition of the physical
plant. In addition, we assess the past performance of an operating project and
prepare financial projections to determine the profitability of the project. We
generally seek to obtain a significant equity interest in a project and to
obtain the operation and maintenance contract for that project. See
"-- Strategy" and "Risk Factors -- " We face risks associated with our power
project development and acquisition activities.
We have grown substantially in recent years as a result of acquisitions of
interests in power generation facilities and steam fields. We believe that
although the domestic power industry is undergoing consolidation and that
significant acquisition opportunities are available, we are likely to confront
significant competition for acquisition opportunities. In addition, there can be
no assurance that we will continue to identify attractive acquisition
opportunities at favorable prices or, to the extent that any opportunities are
identified, that we will be able to consummate such acquisitions.
Pending Acquisitions
Sonoma County Power Plants. On January 26, 1999, we announced that we had
entered into definitive agreements to acquire 12 geothermal facilities from PG&E
in Sonoma County, California (the "Sonoma County Power Plants"), having a
combined capacity of 544 megawatts, for an aggregate investment of $139.0
million. We currently own a portion of the steam fields supplying the Sonoma
County Power Plants and have agreed to purchase the remaining steam fields from
Unocal Corporation for $101.0 million. We expect to complete the steam field
acquisition in March 1999 and the acquisition of the Sonoma County Power Plants
upon receipt of approval by the California Public Utilities Commission ("CPUC")
and FERC, currently anticipated to occur in April 1999. There can be no
assurance that such approvals will be obtained or that we will successfully
complete these acquisitions.
Lake County Power Plants. On December 1, 1998, we announced that we had
exercised our right of first refusal to acquire two geothermal facilities from
PG&E in Lake County, California (the "Lake County Power Plants"), having a
combined capacity of 150 megawatts, for $75.3 million. We currently own the
steam field operations currently supplying the Lake County Power Plants. We
expect to complete this acquisition upon receipt of the approval by the CPUC and
FERC, currently anticipated to occur in April 1999. There can be no assurance
that such approvals will be obtained or that we will successfully consummate
this acquisition.
We anticipate that these acquisitions will enable us to consolidate our
operations in The Geysers into a single ownership structure and to integrate the
power plant and steam field operations, allowing us to optimize the efficiency
and performance of the facilities. We believe that these acquisitions will
provide us with significant synergies that leverage our expertise in geothermal
power generation and position us to benefit from the demand for "green" energy
in the competitive market.
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PROJECT DEVELOPMENT
The development of power generation projects involves numerous elements,
including evaluating and selecting development opportunities, designing and
engineering the project, obtaining power sales agreements, acquiring necessary
land rights, permits and fuel resources, obtaining financing and managing
construction. We intend to focus primarily on development opportunities where we
are able to capitalize on our expertise in implementing an innovative and fully
integrated approach to project development in which we control the entire
development process. Utilizing this approach, we believe that we are able to
enhance the value of our projects throughout each stage of development in an
effort to maximize our return on investment.
We are pursuing the development of highly efficient, low-cost power plants
that seek to take advantage of inefficiencies in the electricity market. We
intend to sell all or a portion of the power generated by such plants into the
competitive market through a portfolio of short-, medium-and long-term power
sales agreements. We expect that these projects will represent a prototype for
our future plant developments. See "-- Strategy" and "Risk Factors -- " We face
risks associated with our power project development and acquisition activities.
The development of power generation facilities is subject to substantial
risks. In connection with the development of a power generation facility, we
must generally obtain power 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 we 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 we 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, and obtaining all
required governmental permits and approvals, the development of a power project
may require us 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 we were unable
to complete the development of a facility, we would generally not be able to
recover our 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. We cannot assure that we will be successful
in the development of power generation facilities in the future.
Projects Under Construction
Westbrook Power Plant. In February 1999, we acquired from Genesis Power
Corporation ("Genesis"), a New England based power developer, the development
rights to a 540 megawatt gas-fired combined-cycle power plant to be located in
Westbrook, Maine (the "Westbrook Power Plant"). It is estimated that the
development of the Westbrook Power Plant will cost approximately $300.0 million.
Construction commenced in February 1999 and commercial operation is scheduled
for early 2001. Upon completion, the Westbrook Power Plant will be operated by
our company. It is anticipated that the output generated by the Westbrook Power
Plant will be sold into the New England power market and to wholesale and retail
customers in the northeastern United States.
Pasadena Expansion. We are currently expanding the Pasadena Power Plant by
an additional 510 megawatts. Construction began in November 1998 and commercial
operation is expected to begin in June 2000. The electricity output from this
expansion will be sold into the competitive market through our power sales
activities.
Tiverton Power Plant. In September 1998, we invested $40.0 million of
equity in the development of a 265 megawatt gas-fired power plant to be located
in Tiverton, Rhode Island (the "Tiverton Power Plant"). The Tiverton Power Plant
is being developed by Energy Management Inc. ("EMI"). It is estimated that the
development of the Tiverton Power Plant will cost approximately $172.5 million.
For our investment in the Tiverton Power Plant, we will earn 62.8% of the
Tiverton Power Plant project cash flow until a specified pre-tax return is
reached, whereupon our company and EMI will share projected cash flows equally
through the
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remaining life of the project. Construction commenced in late 1998 and
commercial operation is currently scheduled for 2000. Upon completion, the
Tiverton Power Plant will be operated by EMI and will sell its output in the New
England power market and to wholesale and retail customers in the northeastern
United States.
Rumford Power Plant. In November 1998, we invested $40.0 million of equity
in the development of a 265 megawatt gas-fired power plant to be located in
Rumford, Maine (the "Rumford Power Plant"). The Rumford Power Plant is being
developed by EMI. It is estimated that the development of the Rumford Power
Plant will cost approximately $160.0 million. For our investment in the Rumford
Power Plant, we will earn 66.7% of the Rumford Power Plant project cash flow
until a specified pre-tax return is reached, whereupon our company and EMI will
share projected cash flows equally through the remaining life of the project.
Construction commenced in late 1998 and commercial operation is currently
scheduled for 2000. Upon completion, the Rumford Power Plant will be operated by
EMI and will sell its output in the New England power market and to wholesale
and retail customers in the northeastern United States.
Dighton Power Plant. In October 1997, we invested $16.0 million in the
development of a 169 megawatt gas-fired combined-cycle power plant to be located
in Dighton, Massachusetts (the "Dighton Power Plant"). This investment, which is
structured as subordinated debt, will provide us with a preferred payment stream
at a rate of 12.07% per annum for a period of twenty years from the commercial
operation date. It is estimated that the development of the Dighton Power Plant
will cost approximately $120.0 million. The Dighton Power Plant is being
developed by EMI. Construction commenced in the fourth quarter of 1997 and
commercial operation is scheduled to begin in May 1999. Upon completion, the
Dighton Power Plant will be operated by EMI and will sell its output into the
New England power market and to wholesale and retail customers in the
northeastern United States.
Clear Lake Expansion. We are currently expanding the Clear Lake Plant by 35
megawatts through certain capital improvements. Improvements began in late 1998
and commercial operation is expected to begin in December 1999. The electricity
output from this expansion will be sold into the competitive market through our
power sales activities.
Announced Development Projects
Delta Energy Center. On February 3, 1999, we, together with Bechtel
Enterprises, announced plans to develop an 880 megawatt gas-fired cogeneration
project in Pittsburg, California (the "Delta Energy Center"). The Delta Energy
Center will provide steam and electricity to the nearby Dow Chemical Company
facility and market the excess electricity into the California power market. We
anticipate that construction will commence in early 2000 and that operation of
the facility will commence in 2002. We are currently pursuing regulatory agency
permits for this project. On February 3, 1999, our company and Bechtel announced
that the Delta Energy Center has met the California Energy Commission's Data
Adequacy requirements in its Application for Certification.
Magic Valley Power Plant. On May 26, 1998, we announced that we had signed
a 20-year power sales agreement to provide electricity to the Magic Valley
Electric Cooperative, Inc. of Mercedes, Texas beginning in 2001. The power will
be supplied by our Magic Valley Generating Station, a 700 megawatt natural
gas-fired power plant under development in Edinburg, Texas. Magic Valley, a
51,000 member non-profit electric cooperative, initially will purchase from 250
to 400 megawatts of capacity, with an option to purchase additional capacity. We
are marketing additional capacity to other wholesale customers, initially
targeting south Texas. Permitting for the Magic Valley plant is underway, with
construction expected to begin in late 1999.
South Point Power Plant. In May 1998, we announced that we had entered into
a long-term lease agreement with the Fort Mojave Indian Tribe to develop a 500
megawatt gas-fired power plant (the "South Point Power Plant") on the tribe's
reservation in Mojave County, Arizona. The electricity generated will be sold to
the Arizona, Nevada and California power markets. We anticipate that the South
Point Power Plant will commence operation in 2000.
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Sutter Power Plant. In February 1997, we announced plans to develop a 500
megawatt gas-fired combined cycle project in Sutter County, in northern
California (the "Sutter Power Plant"). The Sutter Power Plant would be northern
California's first newly constructed power plant. The Sutter Power Plant is
expected to provide electricity to the deregulated California power market
commencing in the year 2000. We are currently pursuing regulatory agency permits
for this project. On January 21, 1998, we announced that the Sutter Power Plant
has met the California Energy Commission's Data Adequacy requirements in its
Application for Certification.
GAS FIELDS
Montis Niger. On January 31, 1997, we purchased Montis Niger, Inc. a gas
production and pipeline company operating primarily in the Sacramento Basin in
northern California. On July 25, 1997, Montis Niger, Inc. was renamed Calpine
Gas Company. As of January 1, 1998, Calpine Gas Company had approximately 8.1
billion cubic feet of proven natural gas reserves and approximately 13,837 gross
acres and 13,738 net acres under lease in the Sacramento Basin. In addition,
Calpine Gas Company owns and operates an 80-mile pipeline delivering gas to the
Greenleaf 1 and 2 Power Plants which had been either produced by Calpine Gas
Company or purchased from third parties. Calpine Gas Company currently supplies
approximately 79% of the fuel requirements for the Greenleaf 1 and 2 Power
Plants.
Sheridan. On January 27, 1999, we announced that we had acquired a 20%
interest in 82 billion cubic feet of proven natural gas reserves located in the
Sacramento Basin in northern California. Sheridan Energy, Inc. ("Sheridan") owns
the remaining 80% interest in these reserves. In addition, we signed a 10-year
agreement with Sheridan under which we will purchase all of Sheridan's
Sacramento Basin production, which currently approximates 20,000 mmbtu per day.
GOVERNMENT REGULATION
We are subject to complex and stringent energy, environmental and other
governmental laws and regulations at the federal, state and local levels in
connection with the development, ownership and operation of its energy
generation facilities. Federal laws and regulations govern transactions by
electrical and gas utility companies, the types of fuel which may be utilized by
an electric generating plant, the type of energy which may be produced by such a
plant and the ownership of a plant. State utility regulatory commissions must
approve the rates and, in some instances, other terms and conditions under which
public utilities purchase electric power from independent producers and sell
retail electric power. Under certain circumstances where specific exemptions are
otherwise unavailable, state utility regulatory commissions may have broad
jurisdiction over non-utility electric power plants. Energy producing projects
also are subject to federal, state and local laws and administrative regulations
which govern the emissions and other substances produced, discharged or disposed
of by a plant and the geographical location, zoning, land use and operation of a
plant. Applicable federal environmental laws typically have both state and local
enforcement and implementation provisions. These environmental laws and
regulations generally require that a wide variety of permits and other approvals
be obtained before the commencement of construction or operation of an
energy-producing facility and that the facility then operate in compliance with
such permits and approvals.
FEDERAL ENERGY REGULATION
PURPA
The enactment of the Public Utility Regulatory Policies Act of 1978, as
amended ("PURPA") and the adoption of regulations thereunder by FERC provided
incentives for the development of cogeneration facilities and small power
production facilities (those utilizing renewable fuels and having a capacity of
less than 80 megawatts).
A domestic electricity generating project must be a QF under FERC
regulations in order to take advantage of certain rate and regulatory incentives
provided by PURPA. PURPA exempts owners of QFs from the Public Utility Holding
Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions
of the Federal Power Act (the "FPA") and, except under certain limited
circumstances, state
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laws concerning rate or financial regulation. These exemptions are important to
us and our competitors. We believe that each of the electricity generating
projects in which we own an interest currently meets the requirements under
PURPA necessary for QF status.
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. 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. A geothermal facility may qualify as a QF if it produces less than 80
megawatts of electricity. 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.
We endeavor to develop our projects, monitor compliance by the projects
with applicable regulations and choose our 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 our
control. For example, loss of a thermal energy customer or failure of a thermal
energy customer to take required amounts of thermal energy from a cogeneration
facility that is a QF could cause the facility to fail requirements regarding
the level of useful thermal energy output. Upon the occurrence of such an event,
we 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 facilities in which we have 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 us 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 our 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.
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. We do not know whether such legislation will be passed or
what form it may take. We believe that if any such legislation is passed, it
would
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apply only to new projects. As a result, although such legislation may adversely
affect our ability to develop new projects, we believe it would not affect our
existing QFs. There can be no assurance, however, that any legislation passed
would not adversely impact our existing projects.
Public Utility Holding Company Regulation
Under PUHCA, any corporation, partnership or other legal entity which owns
or controls 10% or more of the outstanding voting securities of a "public
utility company" or a company which is a "holding company" for a public utility
company is subject to registration with the SEC and regulation under PUHCA,
unless eligible for an exemption. A holding company of a public utility company
that is subject to registration is required by PUHCA to limit its utility
operations to a single integrated utility system and to divest any other
operations not functionally related to the operation of that utility system.
Approval by the SEC is required for nearly all important financial and business
dealings of a registered 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 effect of such
amendments has been to enhance the development of non-QFs which do not have to
meet the fuel, production and ownership requirements of PURPA. We believe that
the amendments could benefit us by expanding our ability to own and operate
facilities that do not qualify for QF status, but they have also resulted in
increased competition by allowing utilities to develop such facilities which are
not subject to the constraints of PUHCA.
Federal Natural Gas Transportation Regulation
We have an ownership interest in 18 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 and terms and conditions for such services are
subject to continuing FERC oversight.
STATE REGULATION
State public utility commissions ("PUCs") have historically had broad
authority to regulate both the rates charged by, and the financial activities
of, electric utilities and to promulgate regulation for implementation of PURPA.
Since a power sales agreement becomes a part of a utility's cost structure
(generally reflected in its retail rates), power sales agreements with
independent electricity producers are potentially under the regulatory purview
of PUCs and in particular the process by which the utility has entered into the
power sales agreements. If a PUC has approved the process by which a utility
secures its power supply, a PUC is generally inclined to "pass through" the
expense associated with an independent power contract to the utility's retail
customer. However, a regulatory commission under certain circumstances may
disallow the full reimbursement to a utility for the cost to purchase power from
a QF. In addition, retail sales of electricity or thermal energy by an
independent power producer may be subject to PUC regulation depending on state
law. Independent power producers which are not QFs under PURPA, or EWGs pursuant
to the Energy Policy Act of 1992, are considered to be public utilities in many
states and are subject to broad regulation by a PUC, ranging from requirement of
certificate of public convenience and necessity to regulation of organizational,
accounting, financial and other corporate matters. States may assert
jurisdiction over the siting and
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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.
In the State of California, restructuring legislation was enacted in
September 1996 and was implemented in 1998. This legislation established 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 responsible for an efficient competitive electric energy
auction open on a non-discriminatory basis to all electric services providers.
Other provisions 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, the unbundling and establishment of rate structure for
historical utility functions, the continuation of public purpose programs and
issues related to issuance of rate reduction bonds.
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 us through implementation of customer choice (direct access), the
California restructuring legislation both recognizes the sanctity of existing
contracts, provides for mitigation of utility horizontal market power through
divestiture of fossil generation and provides 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.
Other states in which we conduct operations either have implemented or are
actively considering similar restructuring legislation.
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 us
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
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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 us. In most cases, analogous state laws also
exist that may impose similar, and in some cases more stringent, requirements on
us 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. We believe that
all of our 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, our
operations have, in certain instances, necessitated variances under applicable
California air pollution control laws. However, we believe that we are 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. We are
required to obtain a wastewater and storm water discharge permit for wastewater
and runoff, respectively, from certain of our facilities. We believe that, with
respect to our geothermal operations, we are exempt from newly promulgated
federal storm water requirements. We believe that we are 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. We believe that we are 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, we are subject to certain solid waste requirements under applicable
California laws. We believe that our 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, we are not subject to liability for any Superfund matters.
However, we generate certain wastes, including hazardous wastes, and sends
certain of our wastes to third-party waste disposal sites. As a result, there
can be no assurance that we will not incur liability under CERCLA in the future.
RISK FACTORS
We have substantial indebtedness that we may be unable to service and that
restricts our activities. We have substantial debt that we incurred to finance
the acquisition and development of power generation facilities. As of December
31, 1998, our total consolidated indebtedness was $1.1 billion, our total
consolidated assets were $1.7 billion and our stockholders' equity was $287.0
million. Whether we will be able to meet our
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debt service obligations and to repay our outstanding indebtedness will be
dependent primarily upon the performance of our power generation facilities.
This high level of indebtedness has important consequences, including:
- limiting our ability to borrow additional amounts for working capital,
capital expenditures, debt service requirements, execution of our growth
strategy, or other purposes,
- limiting our ability to use operating cash flow in other areas of our
business because we must dedicate a substantial portion of these funds to
service the debt,
- increasing our vulnerability to general adverse economic and industry
conditions, and
- limiting our ability to capitalize on business opportunities and to react
to competitive pressures and adverse changes in government regulation.
The operating and financial restrictions and covenants in our existing debt
agreements, including the indentures relating to our outstanding senior notes
and our $100.0 million revolving credit facility, contain restrictive covenants.
Among other things these restrictions limit or prohibit our ability to:
- incur indebtedness,
- make prepayments of indebtedness in whole or in part,
- pay dividends,
- make investments,
- engage in transactions with affiliates,
- create liens,
- sell assets, and
- acquire facilities or other businesses.
Also, if our management or ownership changes, our indentures may require us
to make an offer to purchase our outstanding notes, including the senior notes.
We cannot assure you that we will have the financial resources necessary to
purchase such notes, and our board of directors cannot waive provisions in the
indentures.
We believe that our cash flow from operations, together with other
available sources of funds, including borrowings under our existing borrowing
arrangements, will be adequate to pay principal and interest on our debt and to
enable us to comply with the terms of our debt agreements. If we are unable to
comply with the terms of our debt agreements and fail to generate sufficient
cash flow from operations in the future, we may be required to refinance all or
a portion of our existing debt or to obtain additional financing. However, we
may be unable to refinance or obtain additional financing because of our high
levels of debt and the debt incurrence restrictions under our debt agreements.
If cash flow is insufficient and refinancing or additional financing is
unavailable, we may be forced to default on our debt obligations. In the event
of a default under the terms of any of our indebtedness, the debt holders may
accelerate the maturity of our obligations, which could cause defaults under our
other obligations.
Our ability to repay our debt depends upon the performance of our
subsidiaries. Almost all of our operations are conducted through our
subsidiaries and other affiliates. As a result, we depend almost entirely upon
their earnings and cash flow to service our indebtedness, including our ability
to pay the interest on and principal of our senior notes. The non-recourse
project financing agreements of certain of our subsidiaries and other affiliates
generally restrict their ability to pay dividends, make distributions or
otherwise transfer funds to us prior to the payment of other obligations,
including operating expenses, debt service and reserves.
Our subsidiaries and other affiliates are separate and distinct legal
entities and have no obligation to pay any amounts due on our senior notes, and
do not guarantee the payment of interest on or principal of these notes. The
right of our senior note holders to receive any assets of any of our
subsidiaries or other affiliates upon our liquidation or reorganization will be
subordinated to the claims of any subsidiaries' or other affiliates' creditors
(including trade creditors and holders of debt issued by our subsidiaries or
affiliates).
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While the indentures impose limitations on our ability and the ability of
our subsidiaries to incur additional indebtedness, the indentures do not limit
the amount of non-recourse project financing that our subsidiaries may incur to
finance new power generation facilities.
We may be unable to secure additional financing in the future. Each power
generation facility that we acquire or develop will require substantial capital
investment. Our ability to arrange financing and the cost of the financing are
dependent upon numerous factors. These factors include:
- 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 in us,
- the continued success of our current power generation facilities, and
- provisions of tax and securities laws that are conducive to raising
capital.
Financing for new facilities may not be available to us on acceptable terms
in the future. We have financed our existing power generation facilities using a
variety of leveraged financing structures, primarily consisting of non-recourse
project financing and lease obligations. As of December 31, 1998, we had
approximately $1.1 billion of total consolidated indebtedness, of which
approximately 11% represented non-recourse project financing. Each non-recourse
project financing and lease obligation is structured to be fully paid out of
cash flow provided by the facility or facilities. In the event of a default
under a financing agreement which we do not cure, the lenders or lessors would
generally have rights to the facility and any related assets. In the event of
foreclosure after a default, we might not retain any interest in the facility.
While we intend to utilize non-recourse or lease financing when appropriate,
market conditions and other factors may prevent similar financing for future
facilities. We do not believe the existence of non-recourse or lease financing
will significantly affect our ability to continue to borrow funds in the future
in order to finance new facilities. However, it is possible that we may be
unable to obtain the financing required to develop our power generation
facilities on terms satisfactory to us.
We have from time to time guaranteed certain obligations of our
subsidiaries and other affiliates. Our lenders or lessors may also require us to
guarantee the indebtedness for future facilities. This would render our general
corporate funds vulnerable in the event of a default by the facility or related
subsidiary. Additionally, our indentures may restrict our ability to guarantee
future debt, which could adversely affect our ability to fund new facilities.
Our indentures do not limit the ability of our subsidiaries to incur
non-recourse or lease financing for investment in new facilities.
Revenue under some of our power sales agreements may be reduced
significantly upon their expiration or termination. Most of the electricity we
generate from our existing portfolio is sold under long-term power sales
agreements that expire at various times. When the terms of each of these power
sales agreements expire, it is possible that the price paid to us for the
generation of electricity may be reduced significantly, which would greatly
reduce our revenue under such agreements. The fixed price periods in some of our
long-term power sales agreements have recently expired, and the electricity
under those agreements is now sold at a fluctuating market price. For example,
the price for electricity for two of our power plants, the Bear Canyon (20
megawatts) and West Ford Flat (27 megawatts) power plants, was 13.83 cents per
kilowatt hour under the fixed price periods that recently expired for these
facilities, and is now set at the energy clearing price, which averaged 2.66
cents per kilowatt hour during 1998. As a result, our energy revenue under these
power sales agreements has been materially reduced. This reduction may lower our
results of operations. We expect the forecasted decline in energy revenues will
be partially mitigated by decreased royalties and planned operating cost
reductions at these facilities. In addition, we will continue our strategy of
offsetting these reductions through our acquisition and development program.
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Our power project development and acquisition activities may not be
successful. The development of power generation facilities is subject to
substantial risks. In connection with the development of a power generation
facility, we must generally obtain:
- necessary power generation equipment,
- governmental permits and approvals,
- fuel supply and transportation agreements,
- sufficient equity capital and debt financing,
- electrical transmission agreements, and
- site agreements and construction contracts.
We may be unsuccessful in accomplishing any of these matters or in doing so
on a timely basis. In addition, project development is subject to various
environmental, engineering and construction risks relating to cost-overruns,
delays and performance. Although we may attempt to minimize the financial risks
in the development of a project by securing a favorable power sales agreement,
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 us to expend significant sums for preliminary engineering,
permitting and legal and other expenses before we can determine whether a
project is feasible, economically attractive or financeable. If we were unable
to complete the development of a facility, we would generally not be able to
recover our investment in the project. 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. We cannot assure you that we will be successful in
the development of power generation facilities in the future.
We have grown substantially in recent years as a result of acquisitions of
interests in power generation facilities and steam fields. We believe that
although the domestic power industry is undergoing consolidation and that
significant acquisition opportunities are available, we are likely to confront
significant competition for acquisition opportunities. In addition, we may be
unable to continue to identify attractive acquisition opportunities at favorable
prices or, to the extent that any opportunities are identified, we may be unable
to complete the acquisitions.
Our projects under construction may not commence operation as
scheduled. The commencement of operation of a newly constructed power generation
facility 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 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. The insurance, warranties or performance guarantees, however, may not be
adequate to cover lost revenues or increased expenses. 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 losing our interest in a power generation facility.
In addition, power sales agreements entered into with a utility early in
the development phase of a project may enable the utility to terminate the
agreement, or to retain security posted as liquidated damages, if a project
fails to achieve commercial operation or certain operating levels by specified
dates or fails to make specified payments. In the event a termination right is
exercised the default provisions in a financing agreement may be triggered
(rendering such debt immediately due and payable). As a result, the project may
be rendered insolvent and we may lose our interest in the project.
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Our power generation facilities may not operate as planned. Upon
completion of our pending acquisitions and projects currently under
construction, we will operate 31 of the 40 power plants in which we will have an
interest. The continued operation of power generation facilities 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. Although from time to time our
power generation facilities have experienced equipment breakdowns or failures,
these breakdowns or failures have not had a significant effect on the operation
of the facilities or on our results of operations. As of December 31, 1998, our
power generation facilities have operated at an average availability of
approximately 96.5%. Although our facilities contain various redundancies and
back-up mechanisms, a breakdown or failure may prevent the affected facility
from performing under applicable power sales agreements. In addition, although
insurance is maintained to protect against operating risks, the proceeds of
insurance may not be adequate to cover lost revenues or increased expenses. As a
result, we could be unable to service principal and interest payments under our
financing obligations which could result in losing our interest in the power
generation facility.
Our geothermal energy reserves may be inadequate for our operations. 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,
- operating expenses relating to the extraction of fluids,
- price levels relating to the extraction of fluids, and
- capital expenditure requirements relating primarily to the drilling of
new wells.
In connection with each geothermal power plant, we estimate the
productivity of the geothermal resource and the expected decline in
productivity. The productivity of a geothermal resource may decline more than
anticipated, resulting in insufficient reserves being available for sustained
generation of the electrical power capacity desired. An incorrect estimate by us
or an unexpected decline in productivity could lower our results of operations.
Geothermal reservoirs are highly complex. 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 ours. 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 we have
extensive experience in the operation and development of geothermal energy
resources and in preparing such estimates, we cannot assure you that we will be
able to successfully manage the development and operation of our geothermal
reservoirs or that we will accurately estimate the quantity or productivity of
our steam reserves.
We depend on our electricity and thermal energy customers. Each of our
power generation facilities currently relies on one or more power sales
agreements with one or more utility or other customers for all or substantially
all of such facility's revenue. In addition, the sales of electricity to two
utility customers during 1998 comprised approximately 64% of our total revenue
during that year. The loss of any one power sales agreement with any of these
customers could have a negative effect on our results of operations. In
addition, any material failure by any customer to fulfill its obligations under
a power sales agreement could have a negative effect on the cash flow available
to us and on our results of operations.
We are subject to complex government regulation which could adversely
affect our operations. Our activities are subject to complex and stringent
energy, environmental and other governmental laws and
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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 we believe that we have
obtained the requisite approvals for our existing operations and that our
business is operated in accordance with applicable laws, we remain subject to a
varied and complex body of laws and regulations that both public officials and
private individuals may seek to enforce. Existing laws and regulations may be
revised or new laws and regulations may become applicable to us that may have a
negative effect on our business and results of operations. We may be unable to
obtain all necessary licenses, permits, approvals and certificates for proposed
projects, and completed facilities may not 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. Intricate
and changing environmental and other regulatory requirements may necessitate
substantial expenditures to obtain permits. If a project is unable to function
as planned due to changing requirements or local opposition, it may create
expensive delays or significant loss of value in a project.
Our operations are potentially subject to the provisions of various energy
laws and regulations, including the Public Utility Regulatory Policies Act of
1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1955, as
amended ("PUHCA"), and state and local regulations. PUHCA provides for the
extensive regulation of public utility holding companies and their subsidiaries.
PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and
owners of QFs certain exemptions from certain federal and state regulations,
including rate and financial regulations.
Under present federal law, we are not subject to regulation as a holding
company under PUHCA, and will not be subject to such regulation as long as the
plants in which we have an interest (1) qualify as QFs, (2) are subject to
another exemption or waiver or (3) qualify as exempt wholesale generators
("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility
must be not more than 50% owned by an electric utility company or electric
utility holding company. In addition, a QF that is a cogeneration facility, such
as the plants in which we currently have interests, must produce electricity as
well as thermal energy for use in an industrial or commercial process in
specified minimum proportions. The QF also must meet certain minimum energy
efficiency standards. Any geothermal power facility which produces up to 80
megawatts of electricity and meets PURPA ownership requirements is considered a
QF.
If any of the plants in which we have an interest lose their QF status or
if amendments to PURPA are enacted that substantially reduce the benefits
currently afforded QFs, we could become a public utility holding company, which
could subject us to significant federal, state and local regulation, including
rate regulation. If we become a holding company, which could be deemed to occur
prospectively or retroactively to the date that any of our plants loses its QF
status, all our other power plants could lose QF status because, under FICC
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
particular power purchase agreement, allow the power purchaser to cease taking
and any 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. If a power purchaser were to cease taking and paying for
electricity or seek 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. Such events could adversely affect
our ability to service our indebtedness, including our senior notes. See
"Business -- Government Regulation -- Federal Energy Regulation."
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at prices based on avoided costs of energy. We do not know whether this
legislation will be passed or, if passed, what form it may take. We cannot
assure that any legislation passed would not adversely impact our existing
domestic projects.
In addition, many states are implementing or considering regulatory
initiatives designed to increase competition in the domestic power generation
industry and increase access to electric utilities' transmission and
distribution systems for independent power producers and electricity consumers.
In particular, the state of California has restructured its electric industry by
providing for a phased-in competitive power generation industry, with a power
pool and an independent system operator, and for direct access to generation for
all
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power purchasers outside the power exchange under certain circumstances.
Although existing QF power sales contracts are to be honored under such
restructuring, and all of our California operating projects are QFs, until the
new system is fully implemented, it is impossible to predict what impact, if
any, it may have on the operations of those projects.
We may be unable to obtain an adequate supply of natural gas in the
future. To date, our fuel acquisition strategy has included various
combinations of our own gas reserves, gas prepayment contracts and short-,
medium- and long-term supply contracts. In our gas supply arrangements, we
attempt 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. We believe that there will be adequate supplies of natural gas
available at reasonable prices for each of our facilities when current gas
supply agreements expire. However, gas supplies may not be available for the
full term of the facilities' power sales agreements, and gas prices may 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 negative
impact on our results of operations.
Competition could adversely affect our performance. The power generation
industry is characterized by intense competition. We encounter competition from
utilities, industrial companies and other power producers. In recent years,
there has been increasing competition in an effort to obtain power sales
agreements. This competition has contributed to a reduction in electricity
prices. In addition, many states have implemented or are considering regulatory
initiatives designed to increase competition in the domestic power industry.
This competition has put pressure on electric utilities to lower their costs,
including the cost of purchased electricity.
Our international investments may face uncertainties. We have one
investment in geothermal steam fields located in Mexico and may pursue
additional international investments. International investments are subject to
unique risks and uncertainties relating to the political, social and economic
structures of the countries in which we invest. 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.
We depend on our senior management. Our success is largely dependent on
the skills, experience and efforts of our senior management. The loss of the
services of one or more members of our senior management could have a negative
effect on our business and development.
Seismic disturbances could damage our project. Areas where we operate and
are developing many of our geothermal and gas-fired projects are subject to
frequent low-level seismic disturbances. More significant seismic disturbances
are possible. Our existing power generation facilities are built to withstand
relatively significant levels of seismic disturbances, and we believe we
maintain adequate insurance protection. However, earthquake, property damage or
business interruption insurance may be inadequate to cover all potential losses
sustained in the event of serious seismic disturbances. Additionally, insurance
may not continue to be available to us on commercially reasonable terms.
Our results are subject to quarterly and seasonal fluctuations. Our
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:
- the timing and size of acquisitions,
- the completion of development projects, and
- variations in levels of production.
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Additionally, because we receive the majority of capacity payments under
some of our power sales agreements during the months of May through October, our
revenues and results of operations are, to some extent, seasonal.
The price of our common stock is volatile. The market price for our common
stock has been volatile in the past, and several factors could cause the price
to fluctuate substantially in the future. These factors include:
- announcements of developments related to our business,
- fluctuations in our results of operations,
- sales of substantial amounts of our securities into the marketplace,
- general conditions in our industry or the worldwide economy,
- an outbreak of war or hostilities,
- a shortfall in revenues or earnings compared to securities analysts'
expectations,
- changes in analysts' recommendations or projections, and
- announcements of new acquisitions or development projects by us.
The market price of our common stock may fluctuate significantly in the
future, and these fluctuations may be unrelated to our performance. General
market price declines or market volatility in the future could adversely affect
the price of our common stock, and thus, the current market price may not be
indicative of future market prices.
YEAR 2000 COMPLIANCE
Year 2000 Compliance -- The "Year 2000 problem" refers to the fact that
some computer hardware, software and embedded systems were designed to read and
store dates using only the last two digits of the year.
We are coordinating our efforts to address the impact of Year 2000 on our
business through a Year 2000 Project Team comprised of representatives from each
business unit and our Year 2000 Project Office. The Year 2000 Project Office is
charged with addressing additional Year 2000 related issues including, but not
limited to, business continuation and other contingency planning. The Year 2000
Project Team meets regularly to monitor the efforts of assigned staff and
contractors to identify, remediate and test our technology.
The Year 2000 Project Team is focusing on four separate technology domains:
- corporate applications, which include core business systems,
- non-information technology, which includes all operating and control
systems,
- end-user computing systems (that is, systems that are not considered core
business systems but may contain date calculations), and
- business partner and vendor systems.
Corporate Applications -- Corporate applications are those major core
systems, such as customer information, human resources and general ledger, for
which our Management Information Systems department has responsibility. We
utilize PeopleSoft for our major core systems. The PeopleSoft applications we
utilize are in operation and have been determined to be Year 2000 compliant.
Non-Information Technology/Embedded Systems -- Non-information technology
includes such items as power plant operating and control systems,
telecommunications and facilities-based equipment (e.g. telephones and two-way
radios) and other embedded systems. Each business unit is responsible for the
inventory and remediation of its embedded systems. In addition, we are working
with the Electric Power Research Institute, a consortium of power companies,
including investor-owned utilities, to coordinate vendor contacts and product
evaluation. Because many embedded systems are similar across utilities, this
concentrated effort should help to reduce total time expended in this area and
help to ensure that our efforts are consistent with the efforts and practices of
other power companies and utilities.
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An Inventory phase for non-information technology/embedded systems was
completed in October 1998. An Initial Assessment phase was completed in December
1998. We plan to complete remediation of non-compliant systems by the second
quarter of 1999. To date, all embedded systems that we have identified can be
upgraded or modified within our current schedule. The schedule for addressing
Year 2000 issues with respect to mission critical embedded systems is as
follows:
PERCENTAGE
PHASE COMPLETED STATUS ESTIMATED COMPLETION DATE
- ----- ---------- ----------- --------------------------
Inventory.......................... 100% Complete September 1998
Initial Assessment................. 100% Complete November 1998
Detail Assessment.................. 70% In Progress February 1999 - March 1999
Remediation........................ 40% In Progress May 1999 - June 1999
Contingency Planning............... 5% In Progress June 1999 - Sept 1999
Testing of embedded systems is complex because some of the testing must be
completed during power plant scheduled maintenance outages. Much of the testing
will be accomplished in the spring of 1999 during regularly scheduled
maintenance outage periods. At that time, at least one typical unit of each
critical type will be tested by us or in cooperation with other power companies,
and the requirement for further testing will be determined.
End-User Computing Systems -- Some of our business units have developed
systems, databases, spreadsheets, etc. that contain date calculations.
Compliance of individual workstations is also included in this domain. These
systems comprise a relatively small percentage of the required modification in
terms of both number and criticality.
Our end-user computing systems are being inventoried by each business unit
and evaluated and remediated by our MIS staff. We have completed approximately
10% of remediation and testing of the end-user computing systems, and we expect
to complete this process by mid-1999.
Business Partner and Vendor Systems -- We have contracts with business
partners and vendors who provide products and services to us. We are vigorously
seeking to obtain Year 2000 assurances from these third parties. The Year 2000
Project Team and appropriate business units are jointly undertaking this effort.
We have sent letters and accompanying Year 2000 surveys to about 800 vendors and
suppliers. Over 400 responses have been received as of January 31, 1999. These
responses outline to varying degrees the approaches vendors are undertaking to
resolve Year 2000 issues within their own systems. Follow-up letters will be
sent to those vendors who have not responded or whose responses were inadequate.
Contingency Planning -- Contingency and business continuation planning are
in various stages of development for critical and high-priority systems. Our
existing disaster response plan and other contingency plans are currently being
evaluated and will be adopted for use in case of any Year 2000-related
disruption. We expect to complete our contingency planning by September 1999.
Costs -- The costs of expected modifications are currently estimated to be
approximately $1.7 million which will be charged to expense as incurred. From
January 1, 1998 through December 31, 1998, $158,000 has been charged to expense.
Approximately 9% of the estimated total cost was incurred in 1998, and the
remainder will be incurred in 1999 and 2000. These costs have been and will be
funded through operating cash flow. These estimates may change as additional
evaluations are completed and remediation and testing progress.
Risks -- We currently expect to complete our Year 2000 efforts with respect
to critical systems by mid-1999. This schedule and our cost estimates may be
affected by, among other things, the availability of Year 2000 personnel, the
readiness of third parties, the timing for testing our embedded systems, the
availability of vendor resources to complete embedded system assessments and
produce required component upgrades and our ability to implement appropriate
contingency plans.
We produce revenues by selling power we produce to customers. We depend on
transmission and distribution facilities that are owned and operated by
investor-owned utilities to deliver power to our
26
28
customers. If either our customers or the providers of transmission and
distribution facilities experience significant disruptions as a result of the
Year 2000 problem, our ability to sell and deliver power may be hindered, which
could result in a loss of revenue.
The cost or consequences of a materially incomplete or untimely resolution
of the Year 2000 problem could adversely affect our future operations, financial
results or our financial condition.
COMPETITION
The power generation industry is characterized by intense competition, and
we encounter competition from utilities, industrial companies and other power
producers. In recent years, there has been increasing competition in an effort
to obtain power sales agreements, and this competition has contributed to a
reduction in electricity prices. In addition, many states are implementing or
considering regulatory initiatives designed to increase competition in the
domestic power industry. In California, the CPUC issued decisions which provide
for direct access for all customers as of April 1, 1998. Regulatory initiatives
are also being considered in other states, including Texas, New York and states
in New England. See "Business -- Government Regulation -- State Regulation."
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.
EMPLOYEES
As of December 31, 1998, we employed 458 people. None of our employees are
covered by collective bargaining agreements, and we have never experienced a
work stoppage, strike or labor dispute. We consider relations with our employees
to be good.
ITEM 2. PROPERTIES
Our principal executive office is located in San Jose, California, under a
lease that expires in June 2001.
We, through our ownership of CGC and TPC, have 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 TPC's 100% undivided interest in the Thermal
Power Company Steam Fields which are operated by Union Oil. In the Glass
Mountain and Medicine Lake areas in northern California, we hold leasehold
interests in 18 leases comprising approximately 25,028 acres of federal
geothermal resource lands.
In general, under the leases, we have 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. We believe that our leases are valid and
that we has complied with all the requirements and conditions material to their
continued effectiveness. A number of our leases for undeveloped properties may
expire in any given year. Before leases expire, we perform geological
evaluations in an effort to determine the resource potential of the underlying
properties. We cannot assure that we will decide to renew any expiring leases.
We own 77 acres in Sutter County, California where we operate the Greenleaf
1 & 2 Power Plants.
We own Calpine Gas Company, which leases property covering approximately
13,837 gross acres and 13,738 net acres.
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29
We own the Texas City, Clear Lake, and Pasadena Power Plants, who lease 9,
21, and 18 acres, respectively.
We own 40 gross acres and 38 net acres in Edinburg, Texas where we are
developing the Magic Valley project, a 700 megawatt power plant.
ITEM 3. LEGAL PROCEEDINGS
On September 30, 1997, a lawsuit was filed by Indeck North American Power
Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb
plc. and certain other parties, including the Company. Some of Indeck's claims
relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in
Gordonsville Energy Limited Partnership from Northern Hydro Limited and Calpine
Auburndale, Inc.'s acquisition of a 50% interest in Auburndale Power Plant
Partners Limited Partnership from Norweb Power Services (No. 1) Limited. Indeck
is claiming that Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the
Company tortiously interfered with Indeck's contractual rights to purchase such
interests and conspired with other parties to do so. Indeck is seeking $25.0
million in compensatory damages, $25.0 million in punitive damages, and the
recovery of attorneys' fees and costs. In July 1998, the court granted motions
to dismiss, without prejudice, the claims against Calpine Gordonsville, Inc. and
Calpine Auburndale, Inc. In August 1998, Indeck filed an amended complaint and
the defendants filed motions to dismiss. A hearing on those motions is scheduled
for February 1999. The Company is unable to predict the outcome of these
proceedings, but does not believe this will have a material adverse effect on
the Consolidated Financial Statements.
There is currently a dispute between Texas-New Mexico Power Company ("TNP")
and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear
Lake Power Plant, regarding certain costs and other amounts that TNP has
withheld from payments due under the power sales agreement from August 1997
until October 1998. TNP has withheld approximately $450,000 per month related to
transmission charges. In October 1997, CLC filed a petition for declaratory
order with the Texas Public Utilities Commission ("Texas PUC") requesting a
declaration that TNP's withholding is in error, which petition is currently
pending. Also, as of December 31, 1998, TNP has withheld approximately $7.7
million of standby power charges. In addition to the Texas PUC petition, CLC
filed an action in Texas courts on October 2, 1997, alleging TNP's breach of the
power sales agreement and is seeking refund of the standby charges. In October
1998, TNP and CLC reached an agreement in principle to settle all outstanding
disputes. The parties are currently finalizing the documentation of the
settlement which must be approved by the Texas PUC. Both the Texas PUC action
and the court action have been put on hold pending completion of the settlement
and we do not believe that these proceedings will have a materially adverse
effect on the Consolidated Financial Statements.
An action was filed against Lockport Energy Associates, Limited Partnership
("LERA") and the New York Public Service Commission ("NYPSC") in August 1997 by
New York State Electricity and Gas Company ("NYSEG") in the Federal District
Court for the Northern District of New York. NYSEG has requested the Court to
direct NYPSC and the Federal Energy Regulatory Commission (the "FERC") to modify
contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC
filed a cross-claim alleging that the FERC violated Public Utility Regulatory
Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by failing
to reform the NYSEG contract that was previously approved by the NYPSC. Although
it is unable to predict the outcome of this case, in any event, the Company
retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase
the Company's interest in the Lockport Power Plant for $18.9 million, less
equity distributions received by the Company, at any time before December 19,
2001.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. The Company does not expect that the
outcome of these proceedings will have a material adverse effect on the
Company's financial position or results of operations, although no assurance can
be given in this regard.
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30
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 16 of the Notes to
Consolidated Financial Statements to this report. The Company made no sales of
unregistered equity securities in the last three years.
ITEM 6. SELECTED FINANCIAL DATA
The information required hereunder is set forth under "Selected
Consolidated Financial Data" included in Appendix F to this report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information required hereunder is set forth under "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included in Appendix F to this report.
Item 7a. Quantitative Qualitative Disclosure
The information required hereunder is set forth under "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included in Appendix F to this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is set forth under "Report of
Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated
Statements of Operations," "Consolidated Statements of Shareholder's Equity,"
"Consolidated Statements of Cash Flows," and "Notes to Consolidated Financial
Statements" included in Appendix F of this report. Other financial information
and schedules are included in Appendix F of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS AND FINANCIAL DISCLOSURE
None.
ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES
Incorporated by reference from Proxy Statement relating to the 1999 Annual
Meeting of Shareholders to be filed.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Proxy Statement relating to the 1999 Annual
Meeting of Shareholders to be filed.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Proxy Statement relating to the 1999 Annual
Meeting of Shareholders to be filed.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)-1. FINANCIAL STATEMENTS AND OTHER INFORMATION
29
31
The following items appear in Appendix F of this report:
Selected Consolidated Financial Data
Management's Discussion and Analysis of Financial Condition and Results
of Operations
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 1998 and 1997
Consolidated Statements of Operations for the Years Ended December 31,
1998, 1997 and 1996
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1998, 1997 and 1996
Consolidated Statements of Cash Flows for the Years Ended December 31,
1998, 1997 and 1996
Notes to Consolidated Financial Statements for the Years Ended December
31, 1998, 1997 and 1996
(a)-2. FINANCIAL STATEMENTS AND SCHEDULES
CALPINE CORPORATION AND SUBSIDIARIES
Schedule II: Valuation and Qualifying Accounts
The following items appear in Appendix F of this report:
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Independent Auditor's Report
Consolidated Balance Sheet, December 31, 1998 and 1997
Consolidated Statement of Income for the Years Ended December 31,
1998, 1997 and 1996
Consolidated Statements of Changes in Partners' Deficit for the
Years Ended December 31, 1998, 1997 and 1996
Consolidated Statements of Cash Flows for the Years Ended December
31, 1998, 1997 and 1996
Notes to Consolidated Financial Statements for the Years Ended
December 31, 1998, 1997 and 1996
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:
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1 -- Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(b)
3.2 -- Amended and Restated Bylaws of Calpine Corporation, a
Delaware corporation.(b)
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.(d)
4.3 -- Indenture dated as of July 8, 1997 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(g)
4.4 -- Indenture dated as of March 31, 1998 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(l)
10.1 -- Financing Agreements
10.1.1 -- 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)
30
32
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
10.1.2 -- 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)
10.1.3 -- Lease dated as of April 24, 1996 between BAF Energy A
California Limited Partnership, Lessor, and Calpine King
City Cogen, LLC, Lessee.(c)
10.1.4 -- Credit Agreement, dated as of August 28, 1996, among Calpine
Gilroy Cogen, L.P. and Banque Nationale de Paris.(b)
10.1.5 -- Credit Agreement, dated as of September 25, 1996, among
Calpine Corporation and The Bank of Nova Scotia.(c)
10.1.6 -- Credit Agreement, dated December 20, 1996, among Pasadena
Cogeneration L.P. and ING (U.S.) Capital Corporation and The
Bank Parties Hereto.(e)
10.2 -- Purchase Agreements
10.2.1 -- Asset Purchase Agreement, dated as of August 28, 1996, among
Gilroy Energy Company, McCormick & Company, Incorporated and
Calpine Gilroy Cogen, L.P.(d)
10.2.2 -- Noncompetition/Earnings Contingency Agreement, dated as of
August 28, 1996, among Gilroy Energy Company, McCormick &
Company, Incorporated and Calpine Gilroy Cogen, L.P.(d)
10.2.3 -- Purchase and Sale Agreement dated March 27, 1997 for the
purchase and sale of shares of Enron/Dominion Cogen Corp.
Common Stock among Enron Power Corporation and Calpine
Corporation.(i)
10.2.4 -- Stock Purchase and Redemption Agreement dated March 31,
1998, among Dominion Cogen, Inc. Dominion Energy, Inc. and
Calpine Finance.(i)
10.2.5 -- Stock Purchase Agreement Among Gas Energy Inc., Gas Energy
Cogeneration Inc., Calpine Eastern Corporation and Calpine
Corporation dated August 22, 1997.(h)
10.2.6 -- First Amendment to the Stock Purchase Agreement Among Gas
Energy Inc., Gas Cogeneration Inc., The Brooklyn Union Gas
Company and Calpine Eastern Corporation and Calpine
Corporation dated August 22, 1997; as amended on December
19, 1997.(h)
10.2.7 -- Amended and Restated Cogenerated Electricity Sale and
Purchase Agreement by and between Cogenron Inc., and Texas
Utilities Electric Company dated June 12, 1985; as
previously amended, and as amended and restated on December
29, 1997.(h)
10.2.8 -- Agreement for the Purchase of Electrical Power and Energy
between Capital Cogeneration Company Ltd. And Texas-New
Mexico Power Company Agreement.(h)
10.2.9 -- Stock Purchase Agreement dated May 1, 1998 and between
Calpine Corporation and CCNG Investments, L.P.(k)
10.3 -- Power Sales Agreements
10.3.1 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the Bear Canyon Facility, dated November 30,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), Amendment dated October 17, 1985, Second Amendment
dated October 19, 1988, and related documents.(a)
10.3.2 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the Bear Canyon Facility, dated November 29,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), and Modification dated November 29, 1984, Amendment
dated October 17, 1985, Second Amendment dated October 19,
1988, and related documents.(a)
10.3.3 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the West Ford Flat Facility, dated November 13,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), and Amendments dated May 18, 1987, June 22, 1987,
July 3, 1987 and January 21, 1988, and related documents.(a)
10.3.4 -- Agreement for Firm Power Purchase, dated as of February 24,
1989, between Puget Sound Power & Light Company and Sumas
Energy, Inc. and Amendment thereto dated September 30,
1991.(a)
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33
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
10.3.5 -- 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.(b)
10.3.6 -- Amended and Restated Energy Sales Agreement, dated December
16, 1996, between Phillips Petroleum Company and Pasadena
Cogeneration, L.P.(e)
10.4 -- Steam Sales Agreements
10.4.1 -- Amendment to the Steam and Electricity Service Agreement
between Cogenron Inc. and Union Carbide Corporation dated
June 12, 1985.(h)
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)
10.8 -- 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 -- 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)
10.8.5 -- Ground Lease Agreement, between Union Carbide Corporation
and Northern Cogeneration One Company, dated January 1,
1986.(h)
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.(b)
10.9.3 -- Calpine Corporation Employee Stock Purchase Plan and forms
of agreements thereunder.(b)
10.10.1 -- Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright.(b)
10.10.2 -- Senior Vice President Employment Agreement between Calpine
Corporation and Ms. Ann B. Curtis.(b)
10.10.3 -- Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Lynn A. Kerby.(b)
10.10.4 -- Vice President Employment Agreement between Calpine
Corporation and Mr. Ron A. Walter.(b)
10.10.5 -- Vice President Employment Agreement between Calpine
Corporation and Mr. Robert D. Kelly.(b)
10.10.6 -- First Amended and Restated Consulting Contract between
Calpine Corporation and Mr. George J. Stathakis.(b)
10.11 -- Form of Indemnification Agreement for directors and
officers.(b)
21.1 -- Subsidiaries of the Company.(d)
27.0 -- Financial Data Schedule.*
- ---------------
(a) Incorporated by reference to Registrant's Registration Statement on Form S-1
(Registration Statement No. 33-73160).
32
34
(b) Incorporated by reference to Registrant's Registration Statement on Form S-1
(Registration Statement No. 333-07497).
(c) Incorporated by reference to Registrant's Current Report on Form 8-K dated
May 1, 1996 and filed on May 14, 1996.
(d) Incorporated by reference to Registrant's Current Report on Form 8-K dated
August 29, 1996 and filed on September 13, 1996.
(e) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1996, filed on March 27, 1996.
(f) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1997 and filed on May 12, 1997.
(g) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1997 and filed on August 14, 1997.
(h) Incorporated by reference to Registrant's Annual Report on Form 10-K/A dated
December 31, 1997 and filed on April 1, 1998.
(i) Incorporated by reference to Registrant's Current Report on Form 8-K dated
March 31, 1998 and filed on April 14, 1998.
(j) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1998 and filed on April 14, 1998.
(k) Incorporated by reference to Registrant's Current Report on Form 8-K dated
May 26, 1998 and filed on June 9, 1998.
(l) Incorporated by reference to Registrant's Registration Statement on Form
S-4, filed on August 10, 1998 (Registration Statement No. 333-61047).
* Filed herewith.
33
35
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: 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.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ PETER CARTWRIGHT Chairman, President, Chief February 18, 1999
- --------------------------------------------------- Executive and Director
Peter Cartwright (Principal Executive Officer)
/s/ ANN B. CURTIS Executive Vice President and February 18, 1999
- --------------------------------------------------- Director (Principal Financial
Ann B. Curtis and Accounting Officer)
/s/ JEFFREY E. GARTEN Director February 18, 1999
- ---------------------------------------------------
Jeffrey E. Garten
/s/ SUSAN C. SCHWAB Director February 18, 1999
- ---------------------------------------------------
Susan C. Schwab
/s/ GEORGE J. STATHAKIS Director February 18, 1999
- ---------------------------------------------------
George J. Stathakis
/s/ JOHN O. WILSON Director February 18, 1999
- ---------------------------------------------------
John O. Wilson
/s/ V. ORVILLE WRIGHT Director February 18, 1999
- ---------------------------------------------------
V. Orville Wright
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36
(THIS PAGE INTENTIONALLY LEFT BLANK)
35
37
CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND OTHER INFORMATION
DECEMBER 31, 1998
PAGE
----
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-22
Consolidated Balance Sheets December 31, 1998 and 1997...... F-23
Consolidated Statements of Operations for the Years Ended
December 31, 1998, 1997 and 1996.......................... F-24
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1998, 1997 and 1996.............. F-25
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996.......................... F-26
Notes to Consolidated Financial Statements for the Years
Ended December 31, 1998, 1997 and 1996.................... F-27
Schedule II: Valuation and Qualifying Accounts.............. F-51
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Independent Auditor's Report................................ F-52
Consolidated Balance Sheets, December 31, 1998 and 1997..... F-53
Consolidated Statement of Income for the Years Ended
December 31, 1998, 1997 and 1996.......................... F-54
Consolidated Statement of Changes in Partners' Deficit for
the Years Ended December 31, 1998, 1997 and 1996.......... F-55
Consolidated Statement of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996.......................... F-56
Notes to Consolidated Financial Statements for the Years
Ended December 31, 1998,
1997 and 1996............................................. F-57
F-1
38
CALPINE CORPORATION AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT EARNINGS PER SHARE AND RATIO DATA)
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
1994 1995 1996 1997 1998
-------- -------- -------- ---------- ----------
STATEMENT OF OPERATIONS DATA:
Operating revenue.............. $ 97,516 $134,952 $205,919 $ 247,454 $ 528,146
Total revenue.................. 94,762 132,098 214,554 276,321 555,948
Cost of revenue................ 52,845 77,388 129,200 153,308 375,327
Income from operations......... 31,772 42,686 66,791 97,187 146,676
Income before extraordinary
charge...................... 6,021 7,378 18,692 34,699 46,319
Extraordinary charge........... -- -- -- -- 641
Net income..................... 6,021 7,378 18,692 34,699 45,678
Basic earnings per common
share:
Income before extraordinary
charge.................... $ 0.58 $ 0.71 $ 1.45 $ 1.74 $ 2.30
Extraordinary charge........ -- -- -- -- (0.03)
Net income.................. 0.58 0.71 1.45 1.74 2.27
Diluted earnings per common
share:
Income before extraordinary
charge.................... 0.55 0.67 1.26 1.65 2.19
Extraordinary charge........ -- -- -- -- (0.03)
Net income.................. 0.55 0.67 1.26 1.65 2.16
OTHER FINANCIAL DATA AND RATIOS:
Depreciation and
amortization................ $ 21,580 $ 26,896 $ 40,551 $ 48,935 $ 82,913
EBITDA(1)...................... 53,707 69,515 117,379 172,616 255,306
EBITDA to Consolidated Interest
Expense(2).................. 2.23x 2.11x 2.41x 2.60x 2.74x
Total debt to EBITDA........... 6.23x 5.87x 5.12x 4.96x 4.20x
Ratio of earnings to fixed
charges(3).................. 1.52x 1.46x 1.45x 1.64x 1.68x
AS OF DECEMBER 31,
--------------------------------------------------------------
1994 1995 1996 1997 1998
-------- -------- ---------- ---------- ----------
BALANCE SHEET DATA:
Cash and cash equivalents..... $ 22,527 $ 21,810 $ 95,970 $ 48,513 $ 96,532
Property, plant and equipment,
net........................ 335,453 447,751 648,208 736,339 1,094,303
Total assets.................. 421,372 554,531 1,031,397 1,380,915 1,728,946
Non-recourse project financing
(current).................. 22,800 84,708 30,627 112,966 5,450
Non-recourse project financing
(long-term)................ 196,806 190,642 278,640 182,893 114,190
Senior notes.................. 105,000 105,000 285,000 560,000 951,750
Stockholders' equity.......... 18,649 25,227 203,127 239,956 286,966
(The information contained in the Selected Consolidated Financial Data is
derived
from the audited Consolidated Financial Statements of Calpine Corporation and
Subsidiaries.)
(Footnotes on following page)
F-2
39
- ---------------
(1) 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 our ability to service debt. EBITDA should not be
construed as an alternative to either (i) income from operations (determined
in accordance with generally accepted accounting principles) or (ii) cash
flows from operating activities (determined in accordance with generally
accepted accounting principles).
(2) 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 our capital stock.
(3) Earnings are defined as income before provision for taxes, extraordinary
charge 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
40
CALPINE CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Except for historical financial information contained herein, the matters
discussed in this annual report may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding our intent, belief or current
expectations. Prospective investors are cautioned that any such forward-looking
statements are not guarantees of future performance and involve a number of
risks and uncertainties; actual results could differ materially from those
indicated by such forward-looking statements. Among the important factors that
could cause actual results to differ materially from those indicated by such
forward-looking statements are: (i) that the information is of a preliminary
nature and may be subject to further adjustment, (ii) the possible
unavailability of financing, (iii) risks related to the development, acquisition
and operation of power plants, (iv) the impact of avoided cost pricing, energy
price fluctuations and gas price increases, (v) the impact of curtailment, (vi)
the seasonal nature of our business, (vii) start-up risks, (viii) general
operating risks, (ix) the dependence on third parties, (x) risks associated with
international investments, (xi) risks associated with the power marketing
business, (xii) changes in government regulation, (xiii) the availability of
natural gas, (xiv) the effects of competition, (xv) the dependence on senior
management, (xvi) volatility in the our stock price, (xvii) fluctuations in
quarterly results and seasonality, and (xviii) other risks identified from time
to time in our reports and registration statements filed with the Securities and
Exchange Commission.
OVERVIEW
Calpine is engaged in the development, acquisition, ownership and operation
of power generation facilities and the sale of electricity and steam principally
in the United States. At December 31, 1998, we had interests in 22 power plants
and three steam fields predominantly in the United States, having an aggregate
capacity of 3,018 megawatts.
On February 5, 1998, we acquired the remaining 55% interest in, and assumed
operations and maintenance of, the Bethpage Power Plant. We purchased the
remaining interests for approximately $5.0 million. Additionally, on March 31,
1998 we repaid all outstanding project debt of $37.4 million related to the
Bethpage Power Plant.
On March 31, 1998, we completed the acquisition of the remaining 50%
interest in the Texas Cogeneration Company ("TCC"), which is the owner of the
Texas City and Clear Lake Power Plants. We paid $52.8 million in cash and agreed
to make certain contingent purchase payments that could approximate 2.2% of
project revenue beginning in the year 2000, increasing to 2.9% in 2002. As part
of this acquisition, we own a 7.5% interest in the Bayonne Power Plant, a 165
megawatt gas-fired cogeneration power plant located in Bayonne, New Jersey. In
addition, we paid $105.3 million to restructure certain gas contracts related to
this acquisition.
On July 13, 1998, we signed a letter of intent to enter into a joint
venture to develop, own and operate approximately 2,000 megawatts of gas-fired
power plants in northern California primarily to serve the San Francisco Bay
Area. The gas-fired plants are to be constructed by Bechtel and operated by us.
We have announced that the first plant to be developed under the joint venture
will be the Delta Energy Center, an 880 megawatt gas-fired plant located at the
Dow Chemical facility in Pittsburg, California.
On July 17, 1998, we completed the purchase of a 60 megawatt geothermal
power plant located in Sonoma County, California, from the Sacramento Municipal
Utility District ("SMUD") for $13.0 million. We are the owner and operator of
the geothermal steam fields that provide steam to this facility. Under the
agreement, we paid SMUD $10.6 million at closing, and agreed to pay an
additional $2.4 million over the next two years. In connection with the
acquisition, SMUD agreed to purchase up to 50 megawatts of electricity from the
plant at current market prices plus a renewable power premium through 2001. In
addition, SMUD
F-4
41
has the option to purchase 10 megawatts of off-peak power production through
2005. We currently market the excess electricity into the California power
market.
On July 21, 1998, we completed the acquisition of a 70 megawatt gas-fired
power plant from The Dow Chemical Company for approximately $13.1 million. The
power plant is located at Dow's Pittsburg, California chemical facility. We will
sell up to 18 megawatts of electricity to Dow under a ten-year power sales
agreement, with the balance sold to Pacific Gas & Electric Company ("PG&E")
under an existing power sales agreement. In addition, we will sell approximately
200,000 lbs./hr of steam to Dow and to USS-POSCO Industries' nearby steel mill.
In August 1998, we entered into a sale and leaseback transaction for
certain plant and equipment of our Greenleaf 1 & 2 Power Plants, two 49.5
megawatt gas-fired cogeneration facilities located in Sutter County, California,
for a net book value of $108.6 million. Under the terms of the agreement, we
received approximately $559,000 for the sale of all our rights, title and
interest in the stock of Calpine Greenleaf Corporation, and transferred all
non-recourse project financing of $71.6 million and deferred taxes of $21.4
million. A loss of $15.6 million was recorded on the balance sheet and is being
amortized over the term of the lease through June 2014. Additionally, we have an
early purchase option expiring September 30, 2003.
On September 28, 1998, we entered into a partnership agreement with Energy
Management, Inc. ("EMI") to acquire an ownership interest in a 265 megawatt
gas-fired plant under construction in Tiverton, Rhode Island. EMI and Calpine
will be co-general partners for this project, with EMI acting as the managing
general partner. We invested $40.0 million of equity in the power project, which
is scheduled to commence commercial operation in May 2000. We will receive 62.8%
of all cash and income distributions from the Tiverton project until we receive
a 10.5% pre-tax rate of return. Thereafter, we will receive 50% of all
distributions.
On November 18, 1998, we entered into a partnership agreement with EMI to
acquire an ownership interest in a 265 megawatt gas-fired plant under
construction in Rumford, Maine. EMI and Calpine will be co-general partners for
this project, with EMI acting as the managing general partner. We invested $40.0
million of equity in the power project, which is scheduled to commence
commercial operation in July 2000. We will receive 66 2/3% of all cash and
income distributions from the Rumford project until we receive a 10.5% pre-tax
rate of return. Thereafter, we will receive 50% of all distributions.
SELECTED OPERATING INFORMATION
Set forth below is certain selected operating information for the power
plants and steam fields, for which results are consolidated in our consolidated
statements of operations. The information set forth under power plants consists
of the results for the West Ford Flat Power Plant, Bear Canyon Power Plant,
Greenleaf 1 & 2 Power Plants, Watsonville Power Plant, King City Power Plant,
Gilroy Power Plant, the Bethpage Power Plant since its acquisition on February
5, 1998, the Texas City and Clear Lake Power Plants since their acquisition on
March 31, 1998, the Pasadena Power Plant since it began commercial operation on
July 7, 1998, the Sonoma Power Plant since its acquisition on July 17, 1998 and
the Pittsburg Power Plant since its acquisition on July 21, 1998. The
information set forth under steam fields consists of the results for the PG&E
F-5
42
Unit 13 and Unit 16 Steam Fields, the SMUDGEO #1 Steam Fields and the Thermal
Power Company Steam Fields.
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1994 1995 1996 1997 1998
---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
POWER PLANTS:
Electricity revenue (1):
Energy..................... $ 45,912 $ 54,886 $ 93,851 $ 110,879 $ 252,178
Capacity................... $ 7,967 $ 30,485 $ 65,064 $ 84,296 $ 193,535
Megawatt hours produced.... 447,177 1,033,566 1,985,404 2,158,008 9,864,080
Average energy price per
kilowatt hour (2)....... 10.267c 5.310c 4.727c 5.138c 2.557c
STEAM FIELDS:
Steam revenue (3):
Calpine.................... $ 32,631 $ 39,669 $ 40,549 $ 42,102 $ 36,130
Other interest............. $ 2,051 $ -- $ -- $ -- $ --
Megawatt hours produced.... 2,156,492 2,415,059 2,528,874 2,641,422 2,323,623
Average price per kilowatt
hour.................... 1.608c 1.643c 1.603c 1.594c 1.555c
- ---------------
(1) Electricity revenue is composed of fixed capacity payments, which are not
related to production, and variable energy payments, which are related to
production.
(2) Represents variable energy revenue divided by the kilowatt-hours produced.
The significant increase in capacity revenue and the accompanying decline in
average energy price per kilowatt-hour since 1994 primarily reflects the
increase in our megawatt hour production as a result of additional gas-fired
power plants.
(3) The decline in steam revenue between 1998 and 1997 reflects the acquisition
and consolidation of the Sonoma Power Plant and the related steam fields. We
recently announced several acquisitions which we expect to be completed
during the first part of 1999. Once these acquisitions are completed we will
only record electricity revenue.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Revenue -- Total revenue increased 101% to $555.9 million in 1998 compared to
$276.3 million in 1997.
Electricity and steam sales revenue increased 114% to $507.9 million in
1998 compared to $237.3 million in 1997. The increase is primarily attributable
to the acquisition of the remaining interest in the Texas City, Clear Lake and
Bethpage Power Plants and the acquisition of the Pittsburg Power Plant. These
power plants accounted for $245.2 million in additional electricity revenues in
1998. We benefited from the startup of our power plant in Pasadena, Texas, which
became operational in July 1998. This power plant contributed $30.5 million in
revenue during 1998. During 1998, we produced 9,864,080 total electricity
megawatt hours, which was 7,706,072 megawatt hours higher than the same period
in 1997, as a result of the factors described above. We recently announced three
acquisitions, which we expect to complete during 1999, upon government approval.
These acquisitions when completed will eliminate steam revenue for The Geysers,
reflecting the consolidation of the acquired power plants and related steam
fields.
Service contract revenue increased 98% to $20.2 million in 1998 compared to
$10.2 million in 1997. The $10.0 million increase was primarily due to $3.3
million for fuel management fees, and $7.5 million for third party excess gas
sales.
Income from unconsolidated investments in power projects increased 59% to
$25.2 million in 1998 compared to $15.8 million in 1997. The increase of $9.4
million is primarily attributable to our investments in
F-6
43
the Lockport, Stony Brook and Kennedy International Airport Power Plants, which
contributed $5.2 million of equity income during 1998, as well as $2.5 million
of equity income from the Bayonne Power Plant. For the year ended December 31,
1998, we also recorded $11.7 million of equity income from the Sumas Power Plant
compared to $8.5 million for the same period in 1997. These increases in equity
income were partially offset by a $1.1 million decrease from the Auburndale
Power Plant.
Interest income on loans to power projects decreased 80% to $2.6 million in
1998 compared to $13.0 million in 1997. This decrease was attributable to the
acquisition of the remaining 50% interest in TCC on March 31, 1998 and the sale
of a note receivable in December 1997.
Cost of revenue -- Cost of revenue increased to $375.3 million in 1998 compared
to $153.3 million in 1997. The increase of $222.0 million in 1998 was primarily
attributable to increased plant operating, fuel and depreciation expenses as a
result of the acquisition of the remaining interest in the Texas City, Clear
Lake and Bethpage Power Plants, the acquisition of the Pittsburg Power Plant and
the startup of the Pasadena Power Plant. Additionally, service contract expenses
increased $8.8 million for the year ended December 31, 1998, of which $6.6
million was related to costs associated with the sale of third party excess gas
and a $1.8 million increase for fuel management contracts.
General and administrative expenses -- General and administrative expenses
increased 46% to $26.8 million in 1998 compared to $18.3 million in 1997. The
increase was attributable to the continued growth in personnel and overhead
costs necessary to support the overall growth in our operations.
Interest expense -- Interest expense increased 41% to $86.7 million in 1998
compared to $61.5 million in 1997. The increase was primarily attributable to
interest expense of $35.0 million related to the senior notes issued in 1998 and
1997. This increase was partially offset by $3.5 million for the repayment of
non-recourse project financing for our Geysers facilities, $2.9 million for
reduction of the TCC debt, $2.0 million for reduction of the indebtedness of the
Greenleaf 1 & 2 Power Plants and $1.7 million of interest capitalized on the
development and construction of power projects.
Interest income -- Interest income decreased 14% to $12.3 million in 1998
compared to $14.3 million in 1997. The decrease was primarily attributable to
less interest earned on restricted cash in 1998.
Other income, net -- Other income decreased 66% to $1.1 million in 1998 compared
to $3.2 million in 1997. The decrease was primarily attributable to gas refunds
received in 1997.
Provision for income taxes -- The effective income tax rate was approximately
37% in 1998 compared to 35% in 1997. The effective rates were lower than the
statutory rate (federal and state) primarily due to depletion in excess of tax
basis benefits at our geothermal facilities, and a decrease in the California
tax liability due to our expansion into states other than California.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Revenue -- Total revenue increased 29% to $276.3 million in 1997 compared to
$214.6 million in 1996.
Electricity and steam sales revenue increased 19% to $237.3 million in 1997
compared to $199.5 million in 1996. Electricity and steam sales revenue for 1997
reflected a full year of operation at the Gilroy and King City Power Plants,
which contributed to increases in electricity and steam sales revenue in 1997
compared to 1996 of $25.4 million, and $4.3 million, respectively. Electricity
and steam sales revenue for 1997 compared to 1996 was also $6.0 million higher
at the Bear Canyon and West Ford Flat Power Plants as a result of increased
production and an increase in fixed energy prices to 13.83c per kilowatt-hour.
During 1996, the Bear Canyon and West Ford Flat Power Plants experienced the
maximum curtailment allowed under their power sales agreements with PG&E. In May
1997, the power sales agreements for the Bear Canyon and West Ford Flat Power
Plants were modified to remove curtailment. Without such curtailment, these
plants generated an additional $4.2 million in revenues in 1997 as compared to
1996. In addition, Thermal Power Company ("TPC") also contributed $2.7 million
more revenue for 1997 than 1996, primarily due to increased steam sales under
the alternative pricing agreement entered into with PG&E in March 1996.
F-7
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Service contract revenue increased to $10.2 million in 1997 compared to
$6.5 million in 1996. Service contract revenue during 1996 reflected a $2.8
million loss from our electricity trading operations. The increase in service
contract revenue for 1997 was also attributable to $2.8 million of revenue from
the Texas City and Clear Lake Power Plants, which were acquired in June 1997.
Income from unconsolidated investments in power projects increased to $15.8
million in 1997 compared to $6.5 million during 1996. The increase in 1997
compared to 1996 was primarily due to equity income of $6.3 million from our
June 1997 investment in the Texas City and Clear Lake Power Plants and an
increase in equity income of $2.2 million from our investment in Sumas
Cogeneration Company ("Sumas"). In accordance with a power sales agreement with
Puget Sound Power and Light Company, operations at Sumas were significantly
displaced from February to July 1997, and, in exchange, the Sumas Power Plant
received a higher price for energy sold and certain other payments. In addition,
the partnership agreement governing Sumas was amended in September 1997 to
increase our percentage of distributions.
Interest income on loans to power projects increased to $13.0 million in
1997 compared to $2.1 million in 1996. The increase was primarily related to
interest income on the loans made by Calpine Finance Company, a wholly-owned
subsidiary of our company, to the Texas City and Clear Lake Power Plants, and to
interest income on the loans to the sole shareholder of Sumas Energy, Inc., our
partner in Sumas.
Cost of revenue -- Cost of revenue increased 19% to $153.3 million in 1997
compared to $129.2 million in 1996. Plant operating, depreciation, and operating
lease expenses at the Gilroy and King City Power Plants for 1997 reflected a
full year of operations, which contributed to increases in cost of revenue in
1997 compared to 1996 of $13.0 million and $8.3 million, respectively.
Project development expenses -- Project development expenses increased 92% to
$7.5 million in 1997 compared to $3.9 million in 1996, due primarily to expanded
acquisition and development activities.
General and administrative expenses -- General and administrative expenses
increased 24% to $18.3 million in 1997 compared to $14.7 million in 1996. The
increases were primarily due to additional personnel and related expenses
necessary to support our expanding operations.
Interest expense -- Interest expense increased 36% to $61.5 million in 1997 from
$45.3 million in 1996. The increase was attributable to: (1) $10.8 million of
interest expense related to the 8 3/4% Senior Notes Due 2007 issued in July and
September 1997, (2) a $7.3 million increase in interest expense related to the
10 1/2% Senior Notes Due 2006 issued May 1996, (3) a $6.4 million increase in
interest expense on debt related to the Gilroy Power Plant acquired in August
1996 and (4) $5.4 million of interest expense on debt related to the acquisition
of the Texas City and Clear Lake Power Plants. These increases were offset by
$6.2 million of interest capitalized for the development and construction of
power plants, and a $7.6 million decrease in interest expense at Calpine Geysers
Company and TPC due to repayment of debt.
Interest income -- Interest income increased 66% to $14.3 million for 1997
compared with $8.6 million for 1996. Interest income earned on collateral
securities purchased in April 1996 in connection with the King City Power Plant
contributed to an increase in interest income of $1.2 million in 1997 as
compared to 1996. In addition, higher cash and cash equivalent balances
resulting from the issuance of the 8 3/4% Senior Notes Due 2007 during 1997
resulted in higher interest income for 1997 as compared to 1996.
Other income, net -- Other income, net, increased to $3.2 million for 1997
compared with expense of $2.3 million for 1996. In 1997, we recorded a $1.1
million gain on the sale of a note receivable and received a refund of $961,000
from PG&E. In 1996, we recorded a $3.7 million loss for uncollectible amounts
related to an acquisition project.
Provision for income taxes -- The effective rate for the income tax provision
was approximately 35% in 1997 and 33% in 1996. The effective rates were lower
than the statutory tax rate (federal and state) primarily due to depletion in
excess of tax basis benefits at our geothermal facilities, a decrease in the
California taxes paid due to our expansion into states other than California,
and a revision of prior years' tax estimates.
F-8
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LIQUIDITY AND CAPITAL RESOURCES
To date, we have obtained cash from our operations, borrowings under our
credit facilities and other working capital lines, sale of debt and equity, and
proceeds from non-recourse project financing. We utilized this cash to fund our
operations, service debt obligations, fund the acquisition, development and
construction of power generation facilities, finance capital expenditures and
meet our other cash and liquidity needs. The following table summarizes our cash
flow activities for the periods indicated:
YEAR ENDED DECEMBER 31,
-----------------------------------
1996 1997 1998
--------- --------- ---------
(IN THOUSANDS)
--------------
Cash flows from:
Operating activities.............. $ 59,944 $ 108,461 $ 171,233
Investing activities.............. (330,937) (402,158) (406,657)
Financing activities.............. 345,153 246,240 283,443
--------- --------- ---------
Total..................... $ 74,160 $ (47,457) $ 48,019
========= ========= =========
Operating activities for 1998 provided $171.2 million, consisting of
approximately $74.3 million of depreciation and amortization, $45.7 million of
net income, $34.4 million of distributions from unconsolidated investments in
power projects, $13.6 million of deferred income taxes, $5.2 million net
decrease in operating assets, and a $23.4 million net increase in operating
liabilities. This was offset by $25.2 million of income from unconsolidated
investments.
Investing activities for 1998 used $406.7 million, primarily due to $158.1
million for the acquisition of the remaining 50% interest in the Texas City and
Clear Lake Power Plants, $42.4 million for the acquisition of the remaining 55%
interest in the Bethpage Power Plant, $24.0 million of capital expenditures
related to the construction of the Pasadena Power Plant, $13.1 million for the
acquisition of the Pittsburg Power Plant, $11.9 million for the acquisition of
the Sonoma Power Plant, $74.2 million of other capital expenditures, $16.2
million of capitalized project development costs, $40.0 million for the
acquisition of an equity interest in the Tiverton Power Plant, $40.0 million for
the acquisition of an equity interest in the Rumford Power Plant, $7.0 million
of interest capitalized on construction projects, offset by $559,000 related to
the sale and leaseback transaction of the Greenleaf 1 & 2 Power Plants, the
receipt of $13.8 million of loan payments, $6.0 million of maturities of
collateral securities in connection with the King City Power Plant, and $1.1
million of restricted cash.
Financing activities for 1998 provided $283.4 million of cash consisting of
$52.1 million of borrowings for the construction of the Pasadena Power Plant,
$5.8 million of borrowings for contingent consideration in connection with the
acquisition of the Gilroy Power Plant, $394.9 million of net proceeds from
additional financings, and $1.1 million for the issuance of common stock,
partially offset by $162.1 million in repayment of non-recourse project
financing, $8.3 million of repurchase of Senior Notes Due 2006 which includes a
premium paid and accrued interest to the date of repurchase.
At December 31, 1998, cash and cash equivalents were $96.5 million and
working capital was $86.9 million. For 1998, cash and cash equivalents increased
by $48.0 million and working capital increased by $112.6 million as compared to
December 31, 1997.
As a developer, owner and operator of power generation facilities, we are
required to make long-term commitments and investments of substantial capital
for our projects. We historically have financed these capital requirements with
cash from operations, borrowings under our credit facilities, other lines of
credit, non-recourse project financing or long-term debt, and the sale of
equity. We expect to commit significant capital in the near future as a result
of development projects and pending acquisitions which have been announced,
including the Westbrook, Sutter, South Point and Magic Valley Power Plants. We
are also in the process of completing three acquisitions comprising of 14
geothermal power plants located in The Geysers and certain related steam fields.
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We continue to evaluate current and forecasted cash flow as a basis for
financing operating requirements and capital expenditures. We believe that we
will have sufficient liquidity from cash flow from operations, borrowings
available under the lines of credit and working capital to satisfy all
obligations under outstanding indebtedness, to finance anticipated capital
expenditures and to fund working capital requirements for the next twelve
months.
On March 31, 1998, we sold $300.0 million of 7 7/8% Senior Notes Due 2008
which mature on April 1, 2008, with interest payable semi-annually on April 1
and October 1 of each year commencing October 1, 1998 (See Note 7 to the Notes
to Consolidated Financial Statements). On July 24, 1998, we sold an additional
$100.0 million of 7 7/8% Senior Notes Due 2008. After deducting discounts to
initial purchasers and expenses of the offerings, the net proceeds from the sale
of the Senior Notes Due 2008 were approximately $392.3 million. (See Note 7 to
the Notes to Consolidated Financial Statements).
At December 31, 1998, we had a $100.0 million revolving credit facility
available with a consortium of commercial lending institutions. We had no
borrowings and $26.4 million of letters of credit outstanding under the credit
facility (See Note 8 to the Notes to Consolidated Financial Statements). The
credit facility contains certain restrictions that limit or prohibit, among
other things, the ability of Calpine or its subsidiaries to incur indebtedness,
make payments of certain indebtedness, pay dividends, make investments, engage
in transactions with affiliates, create liens, sell assets and engage in mergers
and consolidations.
At December 31, 1998, we also had $105.0 million of outstanding 9 1/4%
Senior Notes Due 2004, which mature on February 1, 2004, with interest payable
semi-annually on February 1 and August 1 of each year. In addition, we had
$171.8 million of outstanding 10 1/2% Senior Notes Due 2006, which mature on May
15, 2006, with interest payable semi-annually on May 15 and November 15 of each
year. During 1997, we issued $275.0 million of 8 3/4% Senior Notes Due 2007,
which mature on July 15, 2007, with interest payable semi-annually on January 15
and July 15 of each year.
At December 31, 1998, we had a $12.0 million letter of credit outstanding
with The Bank of Nova Scotia to secure performance of the Clear Lake Power
Plant.
We have a $1.1 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, 1998, we had no borrowings under this working capital
line and $74,000 of letters of credit outstanding. Borrowings accrue interest at
prime plus 1%.
OUTLOOK
Our strategy is to continue our rapid growth by capitalizing on the
significant opportunities in the power market, primarily through our active
development and acquisition programs. In pursuing our proven growth strategy, we
utilize our extensive management and technical expertise to implement a fully
integrated approach to the acquisition, development and operation of power
generation facilities. This approach uses our expertise in design, engineering,
procurement, finance, construction management, fuel and resource acquisition,
operations and power marketing, which we believe provide us with a competitive
advantage. The key elements of our strategy are as follows:
- Development and expansion of power plants. We are actively pursuing the
development and expansion of highly efficient, low-cost, gas-fired power
plants that replace old and inefficient generating facilities and meet
the demand for new generation. Our strategy is to develop power plants in
strategic geographic locations that enable us to leverage existing power
generation assets and operate the power plants as integrated electric
generation systems. This allows us to achieve significant operating
synergies and efficiencies in fuel procurement, power marketing and
operations and maintenance.
In July 1998, we achieved a key milestone in our development program by
completing the development of our 240 megawatt gas-fired power plant in
Pasadena, Texas. The Pasadena project serves as a prototype for future
development projects. We currently have six new projects under
construction, representing an additional 1,784 megawatts of capacity. Of
these new projects, we are expanding our Pasadena and Clear Lake
facilities by an aggregate of 545 megawatts. In addition, four new
gas-fired
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power plants, which will produce an estimated 1,239 megawatts of
electricity, are currently under construction in Dighton, Massachusetts;
Tiverton, Rhode Island; Rumford, Maine; and Westbrook, Maine. We have
also announced plans to develop additional power generation facilities,
totaling an estimated 2,580 megawatts of electricity, in California,
Texas, Arizona and Maine.
- Acquisition of power plants. Our strategy is to acquire power generating
facilities that meet our stringent acquisition criteria and that provide
significant potential for revenue, cash flow and earnings growth and that
provide the opportunity to enhance the operating efficiencies of the
plants. We have significantly expanded and diversified our project
portfolio through the acquisition of power generation facilities through
the completion of 22 acquisitions to date.
We are currently in the process completing two acquisitions comprising 14
geothermal power plants with an aggregate capacity of 694 megawatts,
located in The Geysers, California. Historically, we have served as the
steam supplier for these facilities, which have been owned and operated
by PG&E. We anticipate that these acquisitions will enable us to
consolidate our operations in The Geysers into a single ownership
structure and to integrate the power plant and steam field operations,
allowing us to optimize the efficiency and performance of the facilities.
We believe that these acquisitions provide us with significant synergies
that leverage our expertise in geothermal power generation and position
us to benefit from the demand for "green" energy in the competitive
market.
- Enhance the performance and efficiency of existing power projects. We
continually seek to maximize the power generation potential of our
operating assets and minimize our operating and maintenance expenses and
fuel costs. This will become even more significant as our portfolio of
power generation facilities expands to an aggregate of 40 power plants
with an aggregate capacity of 4,667 megawatts, after completion of our
pending acquisitions and projects currently under construction. We focus
on operating our plants as an integrated system of power generation,
which enables us to minimize costs and maximize operating efficiencies.
As of December 31, 1998, our power generation facilities have operated at
an average availability of approximately 96.5%. We believe that achieving
and maintaining a low-cost of production will be increasingly important
to compete effectively in the power generation market.
RISK FACTORS
We have substantial indebtedness that we may be unable to service and that
restricts our activities. We have substantial debt that we incurred to finance
the acquisition and development of power generation facilities. As of December
31, 1998, our total consolidated indebtedness was $1.1 billion, our total
consolidated assets were $1.7 billion and our stockholders' equity was $287.0
million. Whether we will be able to meet our debt service obligations and to
repay our outstanding indebtedness will be dependent primarily upon the
performance of our power generation facilities.
This high level of indebtedness has important consequences, including:
- limiting our ability to borrow additional amounts for working capital,
capital expenditures, debt service requirements, execution of our growth
strategy, or other purposes,
- limiting our ability to use operating cash flow in other areas of our
business because we must dedicate a substantial portion of these funds to
service the debt,
- increasing our vulnerability to general adverse economic and industry
conditions, and
- limiting our ability to capitalize on business opportunities and to react
to competitive pressures and adverse changes in government regulation.
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The operating and financial restrictions and covenants in our existing debt
agreements, including the indentures relating to our outstanding senior notes
and our $100.0 million revolving credit facility, contain restrictive covenants.
Among other things these restrictions limit or prohibit our ability to:
- incur indebtedness,
- make prepayments of indebtedness in whole or in part,
- pay dividends,
- make investments,
- engage in transactions with affiliates,
- create liens,
- sell assets, and
- acquire facilities or other businesses.
Also, if our management or ownership changes, our indentures may require us
to make an offer to purchase our outstanding notes, including the senior notes.
We cannot assure you that we will have the financial resources necessary to
purchase such notes, and our board of directors cannot waive provisions in the
indentures. (See Note 7 to Notes to Consolidated Financial Statements).
We believe that our cash flow from operations, together with other
available sources of funds, including borrowings under our existing borrowing
arrangements, will be adequate to pay principal and interest on our debt and to
enable us to comply with the terms of our debt agreements. If we are unable to
comply with the terms of our debt agreements and fail to generate sufficient
cash flow from operations in the future, we may be required to refinance all or
a portion of our existing debt or to obtain additional financing. However, we
may be unable to refinance or obtain additional financing because of our high
levels of debt and the debt incurrence restrictions under our debt agreements.
If cash flow is insufficient and refinancing or additional financing is
unavailable, we may be forced to default on our debt obligations. In the event
of a default under the terms of any of our indebtedness, the debt holders may
accelerate the maturity of our obligations, which could cause defaults under our
other obligations.
Our ability to repay our debt depends upon the performance of our
subsidiaries. Almost all of our operations are conducted through our
subsidiaries and other affiliates. As a result, we depend almost entirely upon
their earnings and cash flow to service our indebtedness, including our ability
to pay the interest on and principal of our senior notes. The non-recourse
project financing agreements of certain of our subsidiaries and other affiliates
generally restrict their ability to pay dividends, make distributions or
otherwise transfer funds to us prior to the payment of other obligations,
including operating expenses, debt service and reserves.
Our subsidiaries and other affiliates are separate and distinct legal
entities and have no obligation to pay any amounts due on our senior notes, and
do not guarantee the payment of interest on or principal of these notes. The
right of our senior note holders to receive any assets of any of our
subsidiaries or other affiliates upon our liquidation or reorganization will be
subordinated to the claims of any subsidiaries' or other affiliates' creditors
(including trade creditors and holders of debt issued by our subsidiaries or
affiliates).
While the indentures impose limitations on our ability and the ability of
our subsidiaries to incur additional indebtedness, the indentures do not limit
the amount of non-recourse project financing that our subsidiaries may incur to
finance new power generation facilities.
We may be unable to secure additional financing in the future. Each power
generation facility that we acquire or develop will require substantial capital
investment. Our ability to arrange financing and the cost of the financing are
dependent upon numerous factors. These factors include:
- general economic and capital market conditions,
- conditions in energy markets,
- regulatory developments,
- credit availability from banks or other lenders,
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- investor confidence in the industry and in us,
- the continued success of our current power generation facilities, and
- provisions of tax and securities laws that are conducive to raising
capital.
Financing for new facilities may not be available to us on acceptable terms
in the future. We have financed our existing power generation facilities using a
variety of leveraged financing structures, primarily consisting of non-recourse
project financing and lease obligations. As of December 31, 1998, we had
approximately $1.1 billion of total consolidated indebtedness, of which
approximately 11% represented non-recourse project financing. Each non-recourse
project financing and lease obligation is structured to be fully paid out of
cash flow provided by the facility or facilities. In the event of a default
under a financing agreement which we do not cure, the lenders or lessors would
generally have rights to the facility and any related assets. In the event of
foreclosure after a default, we might not retain any interest in the facility.
While we intend to utilize non-recourse or lease financing when appropriate,
market conditions and other factors may prevent similar financing for future
facilities. We do not believe the existence of non-recourse or lease financing
will significantly affect our ability to continue to borrow funds in the future
in order to finance new facilities. However, it is possible that we may be
unable to obtain the financing required to develop our power generation
facilities on terms satisfactory to us.
We have from time to time guaranteed certain obligations of our
subsidiaries and other affiliates. Our lenders or lessors may also require us to
guarantee the indebtedness for future facilities. This would render our general
corporate funds vulnerable in the event of a default by the facility or related
subsidiary. Additionally, our indentures may restrict our ability to guarantee
future debt, which could adversely affect our ability to fund new facilities.
Our indentures do not limit the ability of our subsidiaries to incur
non-recourse or lease financing for investment in new facilities.
Revenue under some of our power sales agreements may be reduced
significantly upon their expiration or termination. Most of the electricity we
generate from our existing portfolio is sold under long-term power sales
agreements that expire at various times. When the terms of each of these power
sales agreements expire, it is possible that the price paid to us for the
generation of electricity may be reduced significantly, which would greatly
reduce our revenue under such agreements. The fixed price periods in some of our
long-term power sales agreements have recently expired, and the electricity
under those agreements is now sold at a fluctuating market price. For example,
the price for electricity for two of our power plants, the Bear Canyon (20
megawatts) and West Ford Flat (27 megawatts) power plants, was 13.83 cents per
kilowatt hour under the fixed price periods that recently expired for these
facilities, and is now set at the energy clearing price, which averaged 2.66
cents per kilowatt hour during 1998. As a result, our energy revenue under these
power sales agreements has been materially reduced. This reduction may lower our
results of operations. We expect the forecasted decline in energy revenues will
be partially mitigated by decreased royalties and planned operating cost
reductions at these facilities. In addition, we will continue our strategy of
offsetting these reductions through our acquisition and development program.
Our power project development and acquisition activities may not be
successful. The development of power generation facilities is subject to
substantial risks. In connection with the development of a power generation
facility, we must generally obtain:
- necessary power generation equipment,
- governmental permits and approvals,
- fuel supply and transportation agreements,
- sufficient equity capital and debt financing,
- electrical transmission agreements, and
- site agreements and construction contracts.
We may be unsuccessful in accomplishing any of these matters or in doing so
on a timely basis. In addition, project development is subject to various
environmental, engineering and construction risks relating
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to cost-overruns, delays and performance. Although we may attempt to minimize
the financial risks in the development of a project by securing a favorable
power sales agreement, 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 us to expend significant sums for
preliminary engineering, permitting and legal and other expenses before we can
determine whether a project is feasible, economically attractive or financeable.
If we were unable to complete the development of a facility, we would generally
not be able to recover our investment in the project. 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. We cannot assure you that we will be successful in
the development of power generation facilities in the future.
We have grown substantially in recent years as a result of acquisitions of
interests in power generation facilities and steam fields. We believe that
although the domestic power industry is undergoing consolidation and that
significant acquisition opportunities are available, we are likely to confront
significant competition for acquisition opportunities. In addition, we may be
unable to continue to identify attractive acquisition opportunities at favorable
prices or, to the extent that any opportunities are identified, we may be unable
to complete the acquisitions.
Our projects under construction may not commence operation as
scheduled. The commencement of operation of a newly constructed power generation
facility 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 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. The insurance, warranties or performance guarantees, however, may not be
adequate to cover lost revenues or increased expenses. 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 losing our interest in a power generation facility.
In addition, power sales agreements entered into with a utility early in
the development phase of a project may enable the utility to terminate the
agreement, or to retain security posted as liquidated damages, if a project
fails to achieve commercial operation or certain operating levels by specified
dates or fails to make specified payments. In the event a termination right is
exercised the default provisions in a financing agreement may be triggered
(rendering such debt immediately due and payable). As a result, the project may
be rendered insolvent and we may lose our interest in the project.
Our power generation facilities may not operate as planned. Upon
completion of our pending acquisitions and projects currently under
construction, we will operate 31 of the 40 power plants in which we will have an
interest. The continued operation of power generation facilities 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. Although from time to time our
power generation facilities have experienced equipment breakdowns or failures,
these breakdowns or failures have not had a significant effect on the operation
of the facilities or on our results of operations. As of December 31, 1998, our
power generation facilities have operated at an average availability of
approximately 96.5%. Although our facilities contain various redundancies and
back-up mechanisms, a breakdown or failure may prevent the affected facility
from performing under applicable power sales agreements. In addition, although
insurance is maintained to protect against operating risks, the proceeds of
insurance may not be adequate to cover lost revenues or increased expenses. As a
result, we could be unable to service principal and interest payments under our
financing obligations which could result in losing our interest in the power
generation facility.
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Our geothermal energy reserves may be inadequate for our operations. 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,
- operating expenses relating to the extraction of fluids,
- price levels relating to the extraction of fluids, and
- capital expenditure requirements relating primarily to the drilling of
new wells.
In connection with each geothermal power plant, we estimate the
productivity of the geothermal resource and the expected decline in
productivity. The productivity of a geothermal resource may decline more than
anticipated, resulting in insufficient reserves being available for sustained
generation of the electrical power capacity desired. An incorrect estimate by us
or an unexpected decline in productivity could lower our results of operations.
Geothermal reservoirs are highly complex. 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 ours. 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 we have
extensive experience in the operation and development of geothermal energy
resources and in preparing such estimates, we cannot assure you that we will be
able to successfully manage the development and operation of our geothermal
reservoirs or that we will accurately estimate the quantity or productivity of
our steam reserves.
We depend on our electricity and thermal energy customers. Each of our
power generation facilities currently relies on one or more power sales
agreements with one or more utility or other customers for all or substantially
all of such facility's revenue. In addition, the sales of electricity to two
utility customers during 1998 comprised approximately 64% of our total revenue
during that year. The loss of any one power sales agreement with any of these
customers could have a negative effect on our results of operations. In
addition, any material failure by any customer to fulfill its obligations under
a power sales agreement could have a negative effect on the cash flow available
to us and on our results of operations.
We are subject to complex government regulation which could adversely
affect our operations. Our 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 we believe that we have obtained the
requisite approvals for our existing operations and that our business is
operated in accordance with applicable laws, we remain subject to a varied and
complex body of laws and regulations that both public officials and private
individuals may seek to enforce. Existing laws and regulations may be revised or
new laws and regulations may become applicable to us that may have a negative
effect on our business and results of operations. We may be unable to obtain all
necessary licenses, permits, approvals and certificates for proposed projects,
and completed facilities may not 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. Intricate and changing
environmental and other regulatory requirements may necessitate substantial
expenditures to obtain permits. If a project is unable to function as planned
due to changing requirements or local opposition, it may create expensive delays
or significant loss of value in a project.
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Our operations are potentially subject to the provisions of various energy
laws and regulations, including the Public Utility Regulatory Policies Act of
1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1955, as
amended ("PUHCA"), and state and local regulations. PUHCA provides for the
extensive regulation of public utility holding companies and their subsidiaries.
PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and
owners of QFs certain exemptions from certain federal and state regulations,
including rate and financial regulations.
Under present federal law, we are not subject to regulation as a holding
company under PUHCA, and will not be subject to such regulation as long as the
plants in which we have an interest (1) qualify as QFs, (2) are subject to
another exemption or waiver or (3) qualify as exempt wholesale generators
("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility
must be not more than 50% owned by an electric utility company or electric
utility holding company. In addition, a QF that is a cogeneration facility, such
as the plants in which we currently have interests, must produce electricity as
well as thermal energy for use in an industrial or commercial process in
specified minimum proportions. The QF also must meet certain minimum energy
efficiency standards. Any geothermal power facility which produces up to 80
megawatts of electricity and meets PURPA ownership requirements is considered a
QF.
If any of the plants in which we have an interest lose their QF status or
if amendments to PURPA are enacted that substantially reduce the benefits
currently afforded QFs, we could become a public utility holding company, which
could subject us to significant federal, state and local regulation, including
rate regulation. If we become a holding company, which could be deemed to occur
prospectively or retroactively to the date that any of our plants loses its QF
status, all our other power plants could lose QF status because, under FICC
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
particular power purchase agreement, allow the power purchaser to cease taking
and any 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. If a power purchaser were to cease taking and paying for
electricity or seek 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. Such events could adversely affect
our ability to service our indebtedness, including our senior notes. See
"Business -- Government Regulation -- Federal Energy Regulation."
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at prices based on avoided costs of energy. We do not know whether this
legislation will be passed or, if passed, what form it may take. We cannot
assure that any legislation passed would not adversely impact our existing
domestic projects.
In addition, many states are implementing or considering regulatory
initiatives designed to increase competition in the domestic power generation
industry and increase access to electric utilities' transmission and
distribution systems for independent power producers and electricity consumers.
In particular, the state of California has restructured its electric industry by
providing for a phased-in competitive power generation industry, with a power
pool and an independent system operator, and for direct access to generation for
all power purchasers outside the power exchange under certain circumstances.
Although existing QF power sales contracts are to be honored under such
restructuring, and all of our California operating projects are QFs, until the
new system is fully implemented, it is impossible to predict what impact, if
any, it may have on the operations of those projects.
We may be unable to obtain an adequate supply of natural gas in the
future. To date, our fuel acquisition strategy has included various
combinations of our own gas reserves, gas prepayment contracts and short-,
medium- and long-term supply contracts. In our gas supply arrangements, we
attempt 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. We believe that there will be adequate supplies of natural gas
available at reasonable prices for each of our facilities when current gas
supply agreements expire. However, gas supplies may not be available for the
full term of the facilities' power sales agreements, and gas prices may 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 negative
impact on our results of operations.
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Competition could adversely affect our performance. The power generation
industry is characterized by intense competition. We encounter competition from
utilities, industrial companies and other power producers. In recent years,
there has been increasing competition in an effort to obtain power sales
agreements. This competition has contributed to a reduction in electricity
prices. In addition, many states have implemented or are considering regulatory
initiatives designed to increase competition in the domestic power industry.
This competition has put pressure on electric utilities to lower their costs,
including the cost of purchased electricity.
Our international investments may face uncertainties. We have one
investment in geothermal steam fields located in Mexico and may pursue
additional international investments. International investments are subject to
unique risks and uncertainties relating to the political, social and economic
structures of the countries in which we invest. 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.
We depend on our senior management. Our success is largely dependent on
the skills, experience and efforts of our senior management. The loss of the
services of one or more members of our senior management could have a negative
effect on our business and development.
Seismic disturbances could damage our project. Areas where we operate and
are developing many of our geothermal and gas-fired projects are subject to
frequent low-level seismic disturbances. More significant seismic disturbances
are possible. Our existing power generation facilities are built to withstand
relatively significant levels of seismic disturbances, and we believe we
maintain adequate insurance protection. However, earthquake, property damage or
business interruption insurance may be inadequate to cover all potential losses
sustained in the event of serious seismic disturbances. Additionally, insurance
may not continue to be available to us on commercially reasonable terms.
Our results are subject to quarterly and seasonal fluctuations. Our
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:
- the timing and size of acquisitions,
- the completion of development projects, and
- variations in levels of production.
Additionally, because we receive the majority of capacity payments under
some of our power sales agreements during the months of May through October, our
revenues and results of operations are, to some extent, seasonal.
The price of our common stock is volatile. The market price for our common
stock has been volatile in the past, and several factors could cause the price
to fluctuate substantially in the future. These factors include:
- announcements of developments related to our business,
- fluctuations in our results of operations,
- sales of substantial amounts of our securities into the marketplace,
- general conditions in our industry or the worldwide economy,
- an outbreak of war or hostilities,
- a shortfall in revenues or earnings compared to securities analysts'
expectations,
- changes in analysts' recommendations or projections, and
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- announcements of new acquisitions or development projects by us.
The market price of our common stock may fluctuate significantly in the
future, and these fluctuations may be unrelated to our performance. General
market price declines or market volatility in the future could adversely affect
the price of our common stock, and thus, the current market price may not be
indicative of future market prices.
FINANCIAL MARKET RISKS
From time to time, we use interest rate swap agreements to mitigate our
exposure to interest rate fluctuations. We do not use derivative financial
instruments for speculative or trading purposes. The following table summarized
the fair market value of our existing interest rate swap agreements as of
December 31, 1998 (in thousands):
NOTIONAL WEIGHTED
PRINCIPAL AVERAGE FAIR MARKET
MATURITY DATE AMOUNT INTEREST RATE VALUE
------------- --------- ------------- -----------
2000........................................... $ 28,000 9.9% $ (1,154)
2006........................................... 10,000 7.1% (1,118)
2009........................................... 175,000 6.1% (7,960)
2011........................................... 17,600 6.8% (1,469)
2013........................................... 75,000 7.2% (9,674)
2014........................................... 52,370 6.5% (3,817)
-------- -------- --------
Total................................ $357,970 6.7% $(25,192)
======== ======== ========
Short-term investments. As of December 31, 1998, we has short-term
investments of $19.0 million. These short-term investments consist of highly
liquid investments with maturities between three and twelve months. These
investments are subject to interest rate risk and will fall in value if market
interest rates increase. We have the ability to hold these investments to
maturity, and as a result, we would not expect the value of these investments to
be affected to any significant degree by the effect of a sudden change in market
interest rates. Declines in interest rates over time will reduce our interest
income.
Outstanding debt. As of December 31, 1998, we have outstanding long-term
debt of approximately $1.1 billion primarily made up of $951.8 million of senior
notes and $119.6 million of non-recourse project financing. Our non-recourse
project financing is stated at fair market value and bears a weighted average
interest rate of 6.8%. Our outstanding long-term debt as of December 31, 1998
are as follows (in thousands):
CARRYING FAIR MARKET
MATURITY DATE AMOUNT INTEREST RATE VALUE
------------- -------- ------------- -----------
2004........................................... $105,000 9 1/4% $108,200
2006........................................... 171,750 10 1/2% 188,900
2007........................................... 275,000 8 3/4% 288,800
2018........................................... 400,000 7 7/8% 403,000
-------- --------
Total................................ $951,750 $988,900
======== ========
Gas prices fluctuations. We enter into derivative commodity instruments to
hedge our exposure to the impact of price fluctuations on gas purchases. Such
instruments include regulated natural gas contracts and over-the-counter swaps
and basis hedges with major energy derivative product specialists. All hedge
transactions are subject to our risk management policy which does not permit
speculative positions. These transactions are accounted for under the hedge
method of accounting. Cash flows from derivative instruments are recognized as
incurred through changes in working capital.
We use a sensitivity analysis to evaluate the hypothetical effect that
changes in the market value of natural gas may have on the fair value of our
derivative instruments. This analysis measures the impact on the
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commodity derivative instruments and, thereby, does not consider the underlying
exposure related to the commodity. However, gains and losses on derivative
contracts are expected to be similarly offset by sales at the spot market price.
Due to the short duration of the contracts, time value of money is ignored. The
hypothetical change in fair value is calculated by multiplying the difference
between the hypothetical price and the contractual price by the contractual
volumes.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS
In April 1998, the American Institute of Certified Public Accountants
("AICPA") issued Statement of Position ("SOP") No. 98-5, "Reporting on the Costs
of Start-Up Activities," which is effective for financial statements for fiscal
years beginning after December 15, 1998. For purposes of this SOP, start-up
activities are defined broadly as those one-time activities related to opening a
new facility, conducting business in a new territory, conducting business with a
new class of customer or beneficiary, initiating a new process in an existing
facility, or commencing some new operation. Start-up activities include
activities related to organizing a new entity (commonly referred to as
organization costs). We have assessed the impact and adopted SOP 98-5 as of
December 31, 1998, and determined it to be immaterial to our consolidated
financial statements.
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This Statement establishes
the reporting of information about operating segments in annual financial
statements and requires that enterprises report selected information about
operating segments in interim financial reports to shareholders. SFAS No. 131
also establishes standards for related disclosures about products and services,
geographic areas and major customers. SFAS No. 131 is effective for fiscal years
beginning after December 15, 1997. During 1998, we started the process of
decentralization of our operations and will complete this process during 1999.
This Statement will become effective upon completion of this process. We do not
believe that this pronouncement will have a material impact on our consolidated
financial statements.
In June 1998, FASB also issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Statement establishes accounting and
reporting standards, requiring every derivative instrument be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and require
that a company formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999.
The Statement must be applied to derivative instruments and to certain
derivative instruments embedded in hybrid contracts that were issued, acquired,
or substantively modified after December 31, 1997.
We have not yet analyzed the impact of adopting SFAS No. 133 on the
financial statements and have not determined the timing of or method of the
adoption of SFAS No. 133. However the Statement could increase the volatility of
our earnings.
YEAR 2000 COMPLIANCE
Year 2000 Compliance -- The "Year 2000 problem" refers to the fact that
some computer hardware, software and embedded systems were designed to read and
store dates using only the last two digits of the year.
We are coordinating our efforts to address the impact of Year 2000 on our
business through a Year 2000 Project Team comprised of representatives from each
business unit and our Year 2000 Project Office. The Year 2000 Project Office is
charged with addressing additional Year 2000 related issues including, but not
limited to, business continuation and other contingency planning. The Year 2000
Project Team meets regularly to monitor the efforts of assigned staff and
contractors to identify, remediate and test our technology.
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The Year 2000 Project Team is focusing on four separate technology domains:
- corporate applications, which include core business systems,
- non-information technology, which includes all operating and control
systems,
- end-user computing systems (that is, systems that are not considered core
business systems but may contain date calculations), and
- business partner and vendor systems.
Corporate Applications -- Corporate applications are those major core
systems, such as customer information, human resources and general ledger, for
which our Management Information Systems department has responsibility. We
utilize PeopleSoft for our major core systems. The PeopleSoft applications we
utilize are in operation and have been determined to be Year 2000 compliant.
Non-Information Technology/Embedded Systems -- Non-information technology
includes such items as power plant operating and control systems,
telecommunications and facilities-based equipment (e.g. telephones and two-way
radios) and other embedded systems. Each business unit is responsible for the
inventory and remediation of its embedded systems. In addition, we are working
with the Electric Power Research Institute, a consortium of power companies,
including investor-owned utilities, to coordinate vendor contacts and product
evaluation. Because many embedded systems are similar across utilities, this
concentrated effort should help to reduce total time expended in this area and
help to ensure that our efforts are consistent with the efforts and practices of
other power companies and utilities.
An Inventory phase for non-information technology/embedded systems was
completed in October 1998. An Initial Assessment phase was completed in December
1998. We plan to complete remediation of non-compliant systems by the second
quarter of 1999. To date, all embedded systems that we have identified can be
upgraded or modified within our current schedule. The schedule for addressing
Year 2000 issues with respect to mission critical embedded systems is as
follows:
PERCENTAGE
PHASE COMPLETED STATUS ESTIMATED COMPLETION DATE
- ----- ---------- ----------- --------------------------
Inventory.......................... 100% Complete September 1998
Initial Assessment................. 100% Complete November 1998
Detail Assessment.................. 70% In Progress February 1999 - March 1999
Remediation........................ 40% In Progress May 1999 - June 1999
Contingency Planning............... 5% In Progress June 1999 - Sept 1999
Testing of embedded systems is complex because some of the testing must be
completed during power plant scheduled maintenance outages. Much of the testing
will be accomplished in the spring of 1999 during regularly scheduled
maintenance outage periods. At that time, at least one typical unit of each
critical type will be tested by us or in cooperation with other power companies,
and the requirement for further testing will be determined.
End-User Computing Systems -- Some of our business units have developed
systems, databases, spreadsheets, etc. that contain date calculations.
Compliance of individual workstations is also included in this domain. These
systems comprise a relatively small percentage of the required modification in
terms of both number and criticality.
Our end-user computing systems are being inventoried by each business unit
and evaluated and remediated by our MIS staff. We have completed approximately
10% of remediation and testing of the end-user computing systems, and we expect
to complete this process by mid-1999.
Business Partner and Vendor Systems -- We have contracts with business
partners and vendors who provide products and services to us. We are vigorously
seeking to obtain Year 2000 assurances from these third parties. The Year 2000
Project Team and appropriate business units are jointly undertaking this effort.
We have sent letters and accompanying Year 2000 surveys to about 800 vendors and
suppliers. Over 400 responses have been received as of January 31, 1999. These
responses outline to varying degrees the approaches vendors
F-20
57
are undertaking to resolve Year 2000 issues within their own systems. Follow-up
letters will be sent to those vendors who have not responded or whose responses
were inadequate.
Contingency Planning -- Contingency and business continuation planning are
in various stages of development for critical and high-priority systems. Our
existing disaster response plan and other contingency plans are currently being
evaluated and will be adopted for use in case of any Year 2000-related
disruption. We expect to complete our contingency planning by September 1999.
Costs -- The costs of expected modifications are currently estimated to be
approximately $1.7 million which will be charged to expense as incurred. From
January 1, 1998 through December 31, 1998, $158,000 has been charged to expense.
Approximately 9% of the estimated total cost was incurred in 1998, and the
remainder will be incurred in 1999 and 2000. These costs have been and will be
funded through operating cash flow. These estimates may change as additional
evaluations are completed and remediation and testing progress.
Risks -- We currently expect to complete our Year 2000 efforts with respect
to critical systems by mid-1999. This schedule and our cost estimates may be
affected by, among other things, the availability of Year 2000 personnel, the
readiness of third parties, the timing for testing our embedded systems, the
availability of vendor resources to complete embedded system assessments and
produce required component upgrades and our ability to implement appropriate
contingency plans.
We produce revenues by selling power we produce to customers. We depend on
transmission and distribution facilities that are owned and operated by
investor-owned utilities to deliver power to our customers. If either our
customers or the providers of transmission and distribution facilities
experience significant disruptions as a result of the Year 2000 problem, our
ability to sell and deliver power may be hindered, which could result in a loss
of revenue.
The cost or consequences of a materially incomplete or untimely resolution
of the Year 2000 problem could adversely affect our future operations, financial
results or our financial condition.
F-21
58
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, 1998
and 1997, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1998. 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 the Company
recorded income of $11.7 million, $8.6 million and $6.4 million for the years
ended December 31, 1998, 1997 and 1996, respectively. The financial statements
of Sumas were audited by other auditors whose report has been furnished to us
and our opinion, insofar as it relates to the amounts included for Sumas, is
based solely on the report of the other auditors.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits and the report of the other auditors provide a
reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors,
the financial statements referred to above present fairly, in all material
respects, the financial position of Calpine Corporation and subsidiaries as of
December 31, 1998 and 1997, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
Our audit was conducted for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed under Item 14(a)2 is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not a required part of the basic financial statements.
This schedule has been subjected to the auditing procedures applied in the audit
of the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
San Jose, California
February 5, 1999
F-22
59
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
(IN THOUSANDS)
1998 1997
---------- ----------
ASSETS
Current assets:
Cash and cash equivalents................................. $ 96,532 $ 48,513
Accounts receivable from related parties.................. 4,115 7,672
Accounts receivable....................................... 79,743 35,133
Collateral securities, current portion.................... 3,750 6,036
Loans receivable from related parties, current portion.... -- 30,507
Inventories............................................... 14,194 6,015
Other current assets...................................... 11,169 19,050
---------- ----------
Total current assets.............................. 209,503 152,926
---------- ----------
Property, plant and equipment, net.......................... 1,094,303 736,339
Investments in power projects............................... 221,509 222,542
Project development costs................................... 17,001 4,614
Collateral securities, net of current portion............... 86,920 87,134
Loans receivable from related parties, net of current
portion................................................... -- 101,304
Notes receivable from related parties....................... 10,899 16,053
Restricted cash............................................. 14,454 15,584
Deferred financing costs.................................... 22,789 20,452
Other assets................................................ 51,568 23,967
---------- ----------
Total assets...................................... $1,728,946 $1,380,915
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Non-recourse project financing, current portion........... $ 5,450 $ 112,966
Accounts payable.......................................... 53,190 30,441
Accrued payroll and related expenses...................... 9,588 4,950
Accrued interest payable.................................. 25,600 18,025
Other current liabilities................................. 28,751 12,204
---------- ----------
Total current liabilities......................... 122,579 178,586
---------- ----------
Non-recourse project financing, net of current portion...... 114,190 182,893
Senior notes................................................ 951,750 560,000
Deferred income taxes, net.................................. 159,788 142,050
Deferred lease incentive.................................... 67,814 71,383
Other liabilities........................................... 25,859 6,047
---------- ----------
Total liabilities................................. 1,441,980 1,140,959
---------- ----------
Stockholders' equity:
Preferred stock $0.001 par value per share; authorized
10,000,000 shares; none issued and outstanding in 1998
and 1997............................................... -- --
Common stock, $0.001 par value per share; authorized
100,000,000 shares; issued and outstanding 20,161,581
in 1998 and 20,060,705 shares in 1997.................. 20 20
Additional paid-in capital................................ 168,874 167,542
Retained earnings......................................... 118,072 72,394
---------- ----------
Total stockholders' equity........................ 286,966 239,956
---------- ----------
Total liabilities and stockholders' equity........ $1,728,946 $1,380,915
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-23
60
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1998 1997 1996
-------- -------- --------
Revenue:
Electricity and steam sales.............................. $507,897 $237,277 $199,464
Service contract revenue from related parties............ 20,249 10,177 6,455
Income from unconsolidated investments in power
projects.............................................. 25,240 15,819 6,537
Interest income on loans to power projects............... 2,562 13,048 2,098
-------- -------- --------
Total revenue......................................... 555,948 276,321 214,554
-------- -------- --------
Cost of revenue:
Plant operating expenses................................. 256,079 72,366 61,894
Depreciation............................................. 73,988 47,501 39,818
Production royalties..................................... 10,714 10,803 10,793
Operating lease expenses................................. 17,129 14,031 9,295
Service contract expenses................................ 17,417 8,607 7,400
-------- -------- --------
Total cost of revenue................................. 375,327 153,308 129,200
-------- -------- --------
Gross profit............................................... 180,621 123,013 85,354
Project development expenses............................... 7,165 7,537 3,867
General and administrative expenses........................ 26,780 18,289 14,696
-------- -------- --------
Income from operations................................ 146,676 97,187 66,791
Interest expense........................................... 86,726 61,466 45,294
Interest income............................................ (12,348) (14,285) (8,604)
Other (income) expense..................................... (1,075) (3,153) 2,345
-------- -------- --------
Income before provision for income taxes.............. 73,373 53,159 27,756
Provision for income taxes................................. 27,054 18,460 9,064
-------- -------- --------
Income before extraordinary charge.................... 46,319 34,699 18,692
Extraordinary charge for retirement of debt, net of
tax benefit of $441................................. 641 -- --
-------- -------- --------
Net income............................................ $ 45,678 $ 34,699 $ 18,692
======== ======== ========
Basic earnings per common share:
Weighted average shares of common stock outstanding...... 20,121 19,946 12,903
Income before extraordinary charge....................... $ 2.30 $ 1.74 $ 1.45
Extraordinary charge..................................... $ (0.03) $ -- $ --
Net income............................................... $ 2.27 $ 1.74 $ 1.45
Diluted earnings per common share:
Weighted average shares of common stock outstanding...... 21,164 21,016 14,879
Income before extraordinary charge....................... $ 2.19 $ 1.65 $ 1.26
Extraordinary charge..................................... $ (0.03) $ -- $ --
Net income............................................... $ 2.16 $ 1.65 $ 1.26
The accompanying notes are an integral part of these consolidated financial
statements.
F-24
61
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(IN THOUSANDS)
ADDITIONAL
PREFERRED COMMON PAID-IN RETAINED
STOCK STOCK CAPITAL EARNINGS TOTAL
--------- -------- ---------- -------- --------
Balance, December 31, 1995................... $ -- $ 10 $ 6,214 $ 19,003 $ 25,227
Issuance of 5,000,000 shares of preferred
stock................................... 50 -- 49,950 -- 50,000
Conversion of 5,000,000 shares of preferred
stock to 2,179,487 shares of common
stock................................... (50) 3 47 -- --
Issuance of 7,276,221 shares of common
stock, net.............................. -- 7 109,172 -- 109,179
Tax benefit from stock options exercised... -- -- 29 -- 29
Net income................................. -- -- -- 18,692 18,692
-------- -------- -------- -------- --------
Balance, December 31, 1996................... -- 20 165,412 37,695 203,127
Issuance of 217,305 shares of common stock,
net..................................... -- -- 1,022 -- 1,022
Tax benefit from stock options exercised
and other............................... -- -- 1,108 -- 1,108
Net income................................. -- -- -- 34,699 34,699
-------- -------- -------- -------- --------
Balance, December 31, 1997................... -- 20 167,542 72,394 239,956
-------- -------- -------- -------- --------
Issuance of 100,876 shares of common stock,
net..................................... -- -- 1,110 -- 1,110
Tax benefit from stock options exercised
and other............................... -- -- 222 -- 222
Net income................................. -- -- -- 45,678 45,678
-------- -------- -------- -------- --------
Balance, December 31, 1998................... $ -- $ 20 $168,874 $118,072 $286,966
======== ======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-25
62
CALPLNE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(IN THOUSANDS)
1998 1997 1996
--------- --------- ---------
Cash flows from operating activities:
Net income............................................ $ 45,678 $ 34,699 $ 18,692
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization...................... 74,285 46,819 36,600
Deferred income taxes, net......................... 13,554 15,082 2,028
Income from unconsolidated investments in power
projects......................................... (25,240) (15,819) (6,537)
Distributions from unconsolidated power projects... 34,371 22,950 1,274
Change in operating assets and liabilities:
Accounts receivable.............................. 10,172 7,249 (12,652)
Inventories...................................... (746) (632) 256
Other current assets............................. 24,758 (9,304) 55
Other assets..................................... (28,968) (13,203) 63
Accounts payable and accrued expenses............ 17,484 17,464 16,818
Other liabilities................................ 5,885 3,156 3,347
--------- --------- ---------
Net cash provided by operating activities..... 171,233 108,461 59,944
--------- --------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment.......... (98,220) (107,094) (24,057)
Proceeds from sale and leaseback of plant............. 559 -- --
Acquisitions.......................................... (225,476) (108,671) (149,640)
Investments in unconsolidated power projects.......... (79,787) (100,968) --
Decrease (increase) in loans receivable............... 13,813 (155,622) --
(Increase) decrease in notes receivable............... (1,500) 33,110 (10,176)
Investment in collateral securities................... -- -- (98,446)
Maturities of collateral securities................... 6,030 5,350 2,900
Project development costs............................. (23,206) (11,938) (5,887)
Decrease (increase) in restricted cash................ 1,130 43,675 (45,631)
--------- --------- ---------
Net cash used in investing activities......... (406,657) (402,158) (330,937)
--------- --------- ---------
Cash flows from financing activities:
Borrowings from line of credit........................ -- 14,300 46,861
Repayment of borrowings from line of credit........... -- (14,300) (66,712)
Borrowings from non-recourse project financing........ 57,874 131,600 119,760
Repayments of non-recourse project financing.......... (162,145) (144,529) (84,708)
Proceeds from notes payable and short-term
borrowings......................................... -- -- 45,000
Repayments of notes payable and short-term
borrowings......................................... -- (7,131) (46,177)
Proceeds from issuance of Senior Notes................ 400,000 275,000 180,000
Repurchase of Senior Notes............................ (8,250) -- --
Proceeds from issuance of preferred stock............. -- -- 50,000
Proceeds from issuance of common stock................ 1,110 1,022 109,208
Financing costs....................................... (5,146) (9,722) (8,079)
--------- --------- ---------
Net cash provided by financing activities..... 283,443 246,240 345,153
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents.... 48,019 (47,457) 74,160
Cash and cash equivalents, beginning of period.......... 48,513 95,970 21,810
--------- --------- ---------
Cash and cash equivalents, end of period................ $ 96,532 $ 48,513 $ 95,970
========= ========= =========
Cash paid during the year for:
Interest.............................................. $ 71,971 $ 42,746 $ 43,805
Income taxes.......................................... $ 2,167 $ 9,795 $ 6,947
The accompanying notes are an integral part of these consolidated financial
statements.
F-26
63
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") is engaged in the development, acquisition,
ownership and operation of power generation facilities and the sale of
electricity and steam in the United States and selected international markets.
The Company has ownership interests in and operates gas-fired cogeneration
facilities, geothermal steam fields and geothermal power generation facilities
in northern California, Washington, Texas and various locations on the East
Coast. Each of the generation facilities produces and markets electricity for
sale to utilities and other third party purchasers. Thermal energy produced by
the gas-fired cogeneration facilities is primarily sold to governmental and
industrial users and steam produced by geothermal steam fields is sold to
utility-owned power plants.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The accompanying consolidated financial
statements include accounts of the Company. Wholly-owned and majority-owned
subsidiaries are consolidated. Less-than-majority-owned subsidiaries, and
subsidiaries for which control is deemed to be temporary, are accounted for
using the equity method. For equity method investments, the Company's share of
income is calculated according to the Company's equity ownership or according to
the terms of the appropriate partnership agreement (see Note 4). All significant
intercompany accounts and transactions are eliminated in consolidation. The
Company uses the proportionate consolidation method to account for Thermal Power
Company's ("TPC") 25% interest in jointly owned geothermal properties.
Use of Estimates in Preparation of Financial Statements -- The preparation
of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, and disclosure of contingent assets
and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimates. The most significant estimates with regard to these
financial statements relate to future development costs and total productive
resources of the geothermal facilities (see Property, Plant and Equipment), and
the realization of deferred income taxes (see Note 9).
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.
Inventories -- Operating supplies are valued at the lower of cost or
market. Cost for large replacement parts is determined using the specific
identification method. For the remaining supplies, cost is determined using the
weighted average cost method.
Property, Plant and Equipment, net -- Property, plant and equipment, net
are stated at cost less accumulated depreciation and amortization.
The Company capitalizes costs incurred in connection with the development
of geothermal properties, including costs of drilling wells and overhead
directly related to development activities, together with the costs of
production equipment, the related facilities and the operating power plants.
Geothermal properties include the value attributable to the geothermal resources
of Calpine Geysers Company, L.P. ("CGC") and all of the property, plant and
equipment of TPC. Proceeds from the sale of geothermal properties are applied
against capitalized costs, with no gain or loss recognized. At December 31, 1998
and 1997, the Company had $4.0 million of geothermal leases at Glass Mountain in
northern California recorded as property, plant and equipment, net in the
accompanying consolidated balance sheets. The Company is continuing to pursue
the development of Glass Mountain, and expects to recover the cost of such
leases from the future development of the resource.
F-27
64
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
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 38 years.
The value of the above-market pricing provided in power sales agreements
acquired is recorded in property, plant and equipment, net and is amortized over
the above-market pricing period in the power sales agreement with lives of 22
and 23 years. When assets are disposed of, the cost and related accumulated
depreciation are removed from the accounts, and the resulting gains or losses
are included in results of operations.
As of December 31, 1998 and 1997, the components of property, plant and
equipment, net are as follows (in thousands):
1998 1997
---------- ---------
Geothermal properties............................... $ 312,139 $ 307,152
Buildings, machinery and equipment.................. 653,865 299,018
Power sales agreements.............................. 145,957 145,957
Gas contracts....................................... 122,561 16,618
Other assets........................................ 18,955 11,629
---------- ---------
1,253,477 780,374
Less accumulated depreciation and amortization...... (203,984) (148,390)
---------- ---------
1,049,493 631,984
Land................................................ 1,590 754
Construction in progress............................ 43,220 103,601
---------- ---------
Property, plant and equipment, net.................. $1,094,303 $ 736,339
========== =========
Construction in progress includes costs primarily attributable to the
purchase of four gas-fired turbines which were purchased during 1998 for
projects currently under development.
Capitalized Interest -- The Company capitalizes interest on projects during
the development and construction period. For the years ended December 31, 1998
and 1997, the Company capitalized $7.0 million and $6.2 million, respectively,
of interest in connection with the development and construction of power plants.
There was no capitalized interest in 1996.
Project Development Costs -- The Company capitalizes project development
costs once it is determined that it is probable that such costs will be realized
through the ultimate construction of a power plant. These costs include
professional services, salaries, permits and other costs directly related to the
development of a new project. Outside services and other third party costs are
capitalized for acquisition projects. Upon the start-up of plant operations or
the completion of an acquisition, these costs are generally transferred to
property, plant and equipment, net and amortized over the estimated useful life
of the project. Capitalized
F-28
65
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
project costs are charged to expense when the Company determines that the
project will not be consummated or is impaired.
Collateral Securities -- The Company maintains certain investments in
investment grade collateral securities which are classified as held-to-maturity
and stated at amortized cost. The investments in debt securities mature at
various dates through August 2018 in amounts equal to a portion of the King City
Power Plant lease payments. 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, 1998 and 1997 are as follows (in thousands):
UNREALIZED
AMORTIZED AGGREGATE HOLDING
COST FAIR VALUE GAINS
--------- ---------- ----------
1998
Debt securities issued by the United States
government................................ $61,937 $ 72,857 $10,920
Corporate debt securities................... 28,733 31,730 2,997
------- -------- -------
Total............................. $90,670 $104,587 $13,917
======= ======== =======
1997
Debt securities issued by the United States
government................................ $58,312 $ 63,174 $ 4,862
Corporate debt securities................... 34,858 37,485 2,627
------- -------- -------
Total............................. $93,170 $100,659 $ 7,489
======= ======== =======
Restricted Cash -- The Company is required to maintain cash balances that
are restricted by provisions of its debt agreements, lease agreements and by
regulatory agencies. The Company's debt agreements specify restrictions based on
debt service payments and drilling costs for the following year. Regulatory
agencies require cash to be restricted to ensure that funds will be available to
restore property to its original condition. Restricted cash is invested in
accounts earning market rates; therefore, the carrying value approximates fair
value. Such cash is excluded from cash and cash equivalents for the purposes of
the consolidated statements of cash flows.
Deferred Financing Costs -- Costs incurred in connection with obtaining
financing are deferred and amortized over the term of the related financings,
which range up to 18 years.
Revenue Recognition -- Revenue from electricity and steam sales is
recognized upon transmission to the customer. Revenues from contracts entered
into or acquired since May 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 the methodology described above
to the CGC power sales agreements, the revenues recorded for the years ended
December 31, 1998, 1997, and 1996, would have been approximately $5.5 million,
$20.1 million, and $16.1 million less, respectively.
The Company performs operations and maintenance services for all
consolidated projects in which it has an interest, except for the TPC
steamfields. Revenue from investees is recognized on these contracts when the
services are performed.
Concentrations of Credit Risk -- Financial instruments which potentially
subject the Company to concentrations of credit risk consist primarily of cash,
accounts receivable, notes receivable, and loans
F-29
66
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
receivable. The Company's cash accounts are held by seven FDIC insured banks.
The Company's accounts, and notes receivable are concentrated within entities
engaged in the energy industry (see Note 13), mainly within the United States,
some of which are related parties. The Company also maintains a note receivable
with a company in Mexico (see Note 5). The Company generally does not require
collateral for accounts receivable.
Derivative Financial Instruments -- The Company engages in activities to
manage risks associated with changes in interest rates. The Company has entered
into swap agreements to reduce exposure to interest rate fluctuations in
anticipation of certain debt commitments. The instruments' cash flows mirror
those of the underlying exposure. Unrealized gains and losses relating to the
instruments are being deferred over the lives of the contracts. The premiums
paid on the instruments, as measured at inception, are being amortized over
their respective lives as components of interest expense. Any gains or losses
realized upon the early termination of these instruments are being amortized
over the respective lives of the underlying transaction or recognized
immediately if the transaction is terminated earlier than initially anticipated.
Gains and losses on any instruments not meeting the above criteria would be
recognized in income in the current period. Subsequent gains or losses on the
related financial instrument are recognized in income in each period until the
instrument matures, is terminated or is sold.
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 financial instruments to
manage its exposure to commodity price fluctuations. On December 31, 1998, CPSC
held swap contracts with several entities in order to hedge fuel costs and sale
prices.
At December 31, 1998, CPSC had no net open positions which would expose the
Company to risks of fluctuating market prices. The Company actively manages its
positions, and it is the Company's policy to not have any open positions. Net
gains and losses related to swap contracts are recognized when realized. The
Company's credit risk associated with power contracts results from the
risk-of-loss on non-performance by counter parties. The Company reviews and
assesses counter party risk to limit any material impact to its financial
position and results of operations. The Company does not anticipate
non-performance by the counter parties.
New Accounting Pronouncements -- In April 1998, the American Institute of
Certified Public Accountants ("AICPA") issued Statement of Position ("SOP") No.
98-5, "Reporting on the Costs of Start-Up Activities," which is effective for
financial statements for fiscal years beginning after December 15, 1998. For
purposes of this SOP, start-up activities are defined broadly as those one-time
activities related to opening a new facility, conducting business in a new
territory, conducting business with a new class of customer or beneficiary,
initiating a new process in an existing facility, or commencing some new
operation. Start-up activities include activities related to organizing a new
entity (commonly referred to as organization costs). The Company has assessed
the impact and adopted SOP 98-5 as of December 31, 1998 and determined it to be
immaterial to the Consolidated Financial Statements.
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This Statement establishes
the reporting of information about operating segments in annual financial
statements and requires that enterprises report selected information about
operating segments in interim financial reports to shareholders. SFAS No. 131
also establishes standards for related disclosures about products and services,
geographic areas and major customers. SFAS No. 131 is effective for fiscal years
beginning after December 15, 1997. During 1998, the Company started the process
of decentralization of its operations and will complete this process during
1999. This Statement will become effective upon completion
F-30
67
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
of this process. We do not believe that this pronouncement will have a material
impact on the Consolidated Financial Statements.
In June 1998, FASB also issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". The Statement establishes accounting and
reporting standards, requiring every derivative instrument be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and require
that a company formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999.
The Statement must be applied to derivative instruments and to certain
derivative instruments embedded in hybrid contracts that were issued, acquired,
or substantively modified after December 31, 1997. The Company has not yet
analyzed the impact of adopting SFAS No. 133 on the financial statements and has
not determined the timing of or method of the adoption of SFAS No. 133. However,
the Statement could increase volatility in earnings.
Reclassifications -- Certain prior years' amounts in the Consolidated
Financial Statements have been reclassified where necessary to conform to the
1998 presentation.
3. ACQUISITIONS AND INVESTMENTS
The following acquisitions and investments were consummated during the year
ended December 31, 1998:
Bethpage Transaction
On February 5, 1998, the Company acquired the remaining 55% interest in TBG
Cogen Partners ("TBG Cogen"). The partnership owns the Bethpage Power Plant, a
57 megawatt gas-fired cogeneration facility located on Long Island, NY. The
total purchase price of $5.0 million consisted of: (i) a $4.6 million cash
payment and (ii) a $375,000 option applied toward the purchase, subject to final
adjustments. The Company was also assigned all of General Electric's interest as
operator of the Bethpage Power Plant.
Upon the acquisition of the remaining 55% interest, the Company assumed the
outstanding debt of TBG Cogen. On March 31, 1998, the Company made a payment to
Toronto Dominion, Inc. of approximately $37.4 million to pay off the existing
project debt, accrued interest, and a related interest rate swap with a portion
of the net proceeds from the Senior Notes Due 2008 (see Note 7). The acquisition
was accounted for as a purchase.
Texas City and Clear Lake Transaction
On March 31, 1998, the Company acquired the remaining 50% interest in the
Texas City Power Plant, a 450 megawatt gas-fired cogeneration facility, and the
Clear Lake Power Plant, a 377 megawatt gas-fired cogeneration facility for a
purchase price of $52.8 million in cash. The Company must make certain
contingent purchase payments that could approximate 2.2% of project revenue
beginning in the year 2000, increasing to 2.9% in 2002. The Company acquired the
remaining interests in these plants by purchasing the capital stock of Texas
Cogeneration Company ("TCC") from Dominion Cogen, Inc. ("DCI"). As part of this
transaction, the Company now owns a 7.5% interest in the Bayonne Power Plant, a
gas-fired power plant located in Bayonne, New Jersey. The Company purchases the
majority of its natural gas for the Texas power plants from Enron Capital &
Trade Resources Corp. In connection with the acquisition, the Company paid
approximately $105.3 million to restructure certain gas contracts with Enron
Capital & Trade Resources Corp.
F-31
68
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The purchase of the capital stock from DCI and the payment for the
restructuring of certain gas contracts were funded with a portion of the net
proceeds from the issuance of the Senior Notes Due 2008 (see Note 7). The
acquisition was accounted for as a purchase.
On June 23, 1997, the Company acquired the initial 50% interest in the
Texas City and Clear Lake Power Plants through the acquisition of 50% of the
capital stock of Enron/Dominion Cogen Corp. ("EDCC") from a subsidiary of Enron
Corp. EDCC was subsequently renamed TCC. In addition to the purchase of the
capital stock of TCC in June 1997, the Company purchased from the project
lenders $155.6 million of outstanding debt on the Texas City and Clear Lake
Power Plants (approximately $53.0 million and $102.6 million, respectively).
The following represents unaudited pro forma results of operations for the
years ended December 31, 1998 and 1997 assuming the acquisition occurred as of
January 1, 1997 (in thousands, except per share data):
1998 1997
-------- --------
Revenue................................................ $621,038 $555,955
Net income............................................. $ 53,698 $ 69,275
Basic earnings per share............................... $ 2.67 $ 3.47
Diluted earnings per share............................. $ 2.54 $ 3.30
Sonoma Transaction
On July 17, 1998, the Company completed the purchase of a 60 megawatt
geothermal power plant located in Sonoma County, California from the Sacramento
Municipal Utility District ("SMUD") for $13.0 million. The Company is the owner
and operator of the Sonoma geothermal steam fields (formerly the SMUDGEO#1 Steam
Fields), that provide steam to this facility (the "Sonoma Power Plant"). Under
the agreement, the Company paid SMUD $10.6 million at closing and agreed to pay
an additional $2.4 million over the next two years. In connection with the
acquisition, SMUD agreed to purchase 50 megawatts of electricity from the plant
at current market prices plus a renewable power premium through 2001. In
addition, SMUD has the option to purchase 10 megawatts of peak power production
through 2005. The Company currently markets the excess electricity into the
California power market.
Dow Pittsburg Transaction
On July 21, 1998, the Company completed the acquisition of a 70 megawatt
natural gas-fired power plant from The Dow Chemical Company ("Dow") for
approximately $13.1 million. The power plant is located at Dow's Pittsburg,
California chemical facility. The Company's Pittsburg Power Plant will sell up
to 18 megawatts of electricity to Dow under a ten-year power sales agreement,
with the balance sold to Pacific Gas & Electric Company under an existing power
sales agreement. In addition, the Company will sell approximately 200,000 lbs/hr
of steam to Dow and to USS-POSCO Industries' nearby steel mill.
Tiverton Transaction
On September 28, 1998, the Company entered into a partnership agreement
with Energy Management, Inc. ("EMI") to acquire an ownership interest in a 265
megawatt gas-fired plant under development in Tiverton, Rhode Island. EMI and
the Company will be co-general partners for this project, with EMI acting as the
managing general partner. The Company invested $40.0 million of equity in the
power plant, which is scheduled to go into commercial operation in May 2000. The
Company will receive up to 62.8% of all cash and income distributions from the
Tiverton project until it receives a 10.5% pre-tax rate of return. Thereafter,
the Company will receive 50% of all distributions.
F-32
69
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Rumford Transaction
On November 18, 1998, the Company entered into a partnership agreement with
EMI to acquire an ownership interest in a 265 megawatt gas-fired plant under
construction in Rumford, Maine. EMI and the Company will be co-general partners
for this project, with EMI acting as the managing general partner. The Company
invested $40.0 million of equity in the merchant power plant, which is scheduled
to commence commercial operation in July 2000. The Company will receive up to
66 2/3% of all cash and income distributions from the Rumford project until it
receives a 10.5% pre-tax rate of return. Thereafter, the Company will receive
50% of all distributions.
4. UNCONSOLIDATED INVESTMENTS
Investments in power projects, which are accounted for under the equity
method, are as follows (in thousands):
DECEMBER 31,
OWNERSHIP --------------------
INTEREST 1998 1997
--------- -------- --------
Tiverton Power Plant....................... 50% $ 40,945 $ --
Rumford Power Plant........................ 50% 40,416 --
Kennedy International Airport Power
Plant.................................... 50% 39,156 43,710
Stony Brook Power Plant.................... 50% 20,933 21,350
Auburndale Power Plant..................... 50% 23,527 27,374
Dighton Power Plant........................ 50% 17,970 16,425
Gordonsville Power Plant................... 50% 16,197 15,510
Lockport Power Plant....................... 11% 11,858 11,492
Bayonne Power Plant........................ 7.5% 7,872 --
Aidlin Power Plant......................... 5% 2,635 2,010
Texas Cogeneration Company(1).............. -- -- 80,092
Bethpage Power Plant(3).................... -- -- 4,438
Agnews Power Plant......................... 20% -- 141
-------- --------
Total Unconsolidated
Investments.................... $221,509 $222,542
======== ========
The combined results of operations and financial position of the Company's
equity method affiliates are summarized below (in thousands):
DECEMBER 31,
------------------------------------
1998 1997 1996
---------- ---------- --------
Condensed Statement of Operations:
Operating revenue..................... $ 495,123 $ 271,494 $ 77,417
Net income............................ $ 109,618 $ 30,264 $ 14,021
Company's share of net income......... $ 25,240 $ 15,819 $ 6,537
Condensed Balance Sheet:
Assets................................ $1,274,202 $1,693,454 $235,682
Liabilities........................... $1,000,812 $1,276,922 $200,667
F-33
70
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The following details the Company's income from investments in
unconsolidated power projects and the service contract revenue recorded by the
Company related to those power projects (in thousands):
INCOME FROM UNCONSOLIDATED
INVESTMENTS IN POWER PROJECTS SERVICE CONTRACT REVENUE
------------------------------- ---------------------------
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
1998 1997 1996 1998 1997 1996
-------- -------- ------- ------- ------ ------
Sumas Power Plant (2)............. $11,699 $ 8,565 $6,396 $ 1,654 $2,073 $2,034
Gordonsville Power Plant.......... 3,807 404 -- -- -- --
Lockport Power Plant.............. 3,628 200 -- -- -- --
Texas Cogeneration Company........ 2,922 6,331 -- 1,613 2,782 --
Bayonne Power Plant............... 2,446 -- -- -- -- --
Kennedy International Airport
Power Plant..................... 1,159 (190) -- 803 -- --
Aidlin Power Plant................ 625 454 331 3,281 3,024 3,990
Stony Brook Power Plant........... 252 60 -- 973 -- --
Bethpage Power Plant.............. 165 223 -- 1,480 -- --
Agnews Power Plant................ (86) 17 (190) 1,847 1,712 1,954
Auburndale Power Plant............ (1,377) (245) -- -- -- --
------- ------- ------ ------- ------ ------
Total................... $25,240 $15,819 $6,537 $11,651 $9,591 $7,978
======= ======= ====== ======= ====== ======
The Company received $11.9 million and $20.3 million in distributions from
Sumas for the years ended December 31, 1998 and 1997, respectively. The Company
received $3.3 million and $767,000 in distributions from Lockport for the years
ended December 31, 1998 and 1997. The Company received $4.1 million, $3.1
million, $2.7 million, $2.5 million and $120,000 in distributions from Kennedy
International Airport, Gordonsville, Bayonne, Auburndale and Agnews,
respectively, for the year ended December 31, 1998.
- ---------------
(1) On March 31, 1998, the Company acquired the remaining 50% interest in
Texas Cogeneration Company.
(2) On December 31, 1998, the Partnership agreement governing Sumas
Cogeneration Company, L.P. ("Sumas") was amended changing the
distributions schedule for the Company from the previously amended
agreement dated September 30, 1997. The newly amended agreement
reflects the earnings the Company was entitled to under that agreement
from a variable payment schedule to a fixed payment schedule. On
September 30, 1997, the partnership agreement was amended changing the
distribution percentages to the partners. As provided for in the
amendment, the Company's percentage share of the project's cash flow
increased from 50% to approximately 70% through June 30, 2001, based on
certain specified payments. Thereafter, the Company will receive 50% of
the project's cash flow until a 24.5% pre-tax rate of return on its
original investment is achieved, at which time the Company's equity
interest in the partnership will be reduced to 0.1%. As a result of the
amendment of the partnership agreement and the receipt of certain
distributions during 1997, the Company's investment in Sumas was
reduced to zero. Because the investment has been reduced to zero and
there are no continuing obligations of the Company related to Sumas,
the Company expects that income recorded in future periods will
approximate the amount of cash received from partnership distributions.
(3) On February 5, 1998, the Company acquired the remaining 55% interest in
TBG Cogen Partners.
F-34
71
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
5. NOTES RECEIVABLE
In November 1995, Calpine Vapor Inc. ("Vapor") entered into agreements with
Constructora y Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain
Mexican bank lenders to loan $18.5 million to Coperlasa in connection with a
geothermal steam production contract at the Cerro Prieto geothermal resource
("Cerro Prieto Project") in Baja California, Mexico (see Note 2). The resource
currently produces electricity from geothermal power plants owned and operated
by Comision Federal de Electricidad ("CFE"), Mexico's national utility. The
steam field contract is between Coperlasa and CFE. Vapor receives fees for
technical services provided to the project. At December 31, 1998 and 1997, notes
receivable were $9.4 million and $16.1 million, respectively. Interest accrues
on the outstanding notes receivable at approximately 18.9%. The Company is
deferring the recognition of interest income from this note until the Cerro
Prieto Project generates sufficient cash flows available for distribution to
support the collectibility of accrued interest.
6. NON-RECOURSE PROJECT FINANCING
The components of non-recourse project financing as of December 31, 1998
and 1997 are (in thousands):
INTEREST
RATE(1) DECEMBER 31,
------------ --------------------
PROJECTS 1998 1997 FINAL MATURITY 1998 1997
- -------- ---- ---- -------------- -------- --------
Gilroy Power Plant................ 6.8% 7.1% 2014 $119,640 $120,505
Greenleaf Power Plants............ 8.3% 6.5% 2010 -- 71,947
TCC............................... 8.2% 7.2% 1998 -- 103,407
Pasadena Power Plant.............. 5.8% -- 1998 -- --
-------- --------
Total project related
financing............. 119,640 295,859
Less current portion.............. 5,450 112,966
-------- --------
Long-term project financing....... $114,190 $182,893
======== ========
- ---------------
(1) Weighted average rate before giving effect to amortization of financing cost
or interest rate swaps.
Gilroy Power Plant Debt
In August 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, 1998, BNP had provided a $119.6 million loan consisting of a
15-year tranche in the amount of $87.4 million and an 18-year tranche in the
amount of $32.2 million. As of December 31, 1997, BNP had provided a $120.5
million loan consisting of a 15-year tranche in the amount of $86.9 million and
an 18-year tranche in the amount of $33.6 million. The debt is secured by all of
the assets of the Gilroy Power Plant. Interest accrues at BNP's base rate plus
an applicable margin or at the London Interbank Offered Rate ("LIBOR") plus an
applicable margin. Interest on the loans is payable at least quarterly. The
effective interest rate for 1998, after amortization of financing costs was
6.9%. 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 $119.6 million
debt is repaid semi-annually with a final maturity date of August 28, 2014.
Commitment fees are charged based on the amount of committed unused credit.
The Company entered into five interest rate swap agreements to minimize the
impact of changes in interest rates. These agreements fix the interest on $108.0
million of principal of the Gilroy Power Plant debt at a weighted average
interest rate of 6.7%. The interest rate swap agreements mature through August
2014. The Company is exposed to credit risk in the event of non-performance by
the other parties to the swap agreements.
F-35
72
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The non-recourse project financing is held by a subsidiary of Calpine. The
debt agreement governing the non-recourse project financing generally restrict
the subsidiary's ability to pay dividends, make distributions or otherwise
transfer funds. The dividend restrictions require that the subsidiary provide
for the payment of other obligations, including operating expenses, debt service
and reserves, prior to the payment of dividends, distributions or other
transfers to the Company.
The fair market value of these swaps at December 31, 1998 was approximately
($8,520,000).
Greenleaf Power Plants Debt
In June 1995, the Company entered into an agreement with Sumitomo Bank to
finance the acquisition of the Greenleaf Power Plants. In August 1998, the
Company entered into a sales and leaseback transaction, which resulted in the
transfer of the $71.9 million of project debt to the lessor (see Note 14). Of
the $71.9 million debt outstanding at December 31, 1997, $56.8 million bore
interest at a fixed rate while $15.1 million bore interest at LIBOR, plus an
applicable margin. The effective interest rate for 1998, after amortization for
financing costs was 8.5%. The debt was secured by all of the assets of the
Greenleaf Power Plants. Interest on the loans was payable at least quarterly.
TCC Debt
In June 1997, the Company entered into an agreement with The Bank of Nova
Scotia to finance its acquisition of a 50% interest in TCC and the purchase from
the lenders of $155.6 million of outstanding non-recourse project financing. On
March 31, 1998, the Company repaid $89.6 million from a portion of the net
proceeds from the initial $300.0 million offering of Senior Notes Due 2008 and
the balance of $13.8 million from working capital. The outstanding debt bore
interest at the Bank of Nova Scotia's base rate or LIBOR, plus an applicable
margin. The effective interest rate for 1998, after amortization for financing
costs was 8.6%.
On April 9, 1998, the Company terminated an existing interest rate swap
agreement related to $102.6 million of debt for the Clear Lake Power Plant,
which the Company purchased on June 23, 1997. The Company paid approximately
$3.7 million to close its position with the Bank of Nova Scotia and recorded a
purchase price adjustment of approximately $2.3 million, which was the market
value of the swap on June 23, 1997. The remaining $1.4 million was deferred and
is being amortized over the remaining life of the swap.
Pasadena Power Plant Debt
In December 1996, the Company entered into an agreement with ING (U.S.)
Capital LLC ("ING") to provide $151.8 million of non-recourse project financing
for construction of the Pasadena Power Plant. There were no borrowings as of
December 31, 1997. Borrowings commenced in January 1998. On July 24, 1998, the
Company repaid the $52.1 million remaining balance outstanding from a portion of
the net proceeds of the secondary $100.0 million offering of Senior Notes due
2008. The remaining project construction costs were funded by Senior Notes due
2008 and working capital of the Company. The outstanding debt bore interest at
ING's base rate or the Federal Funds Rate plus an applicable margin or at LIBOR
plus an applicable margin. The effective interest rate for 1998, after giving
effect to the interest rate swap, was 7.9%. Interest on the loans was payable at
least quarterly.
The Company entered into an interest rate swap to minimize the impact of
changes in interest rates. The Company retained this interest swap upon
termination of the underlying project financing and redesignated it to other
floating rate financings. At December 31, 1998, the fair market value of this
interest rate swap was approximately ($9,674,000).
The Company has entered into two anticipatory hedges to fix the interest
rates on future project financings. The Company intends to enter into this
project financings during the first six months of 1999.
F-36
73
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
These anticipatory hedges fix an interest rate on $175.0 million at $6.1%
interest. At December 31, 1998, the fair market value of these hedges was
approximately ($7,960,000) and is being deferred and will be amortized over the
future project financings.
7. SENIOR NOTES
Senior Notes payable consist of the following as of December 31, 1998 and
1997 (in thousands):
DECEMBER 31,
--------------------
INTEREST RATES FIRST CALL DATE 1998 1997
-------------- --------------- -------- --------
Senior Notes due 2004.............. 9 1/4% 1999 $105,000 $105,000
Senior Notes due 2006.............. 10 1/2% 2001 171,750 180,000
Senior Notes due 2007.............. 8 3/4% 2002 275,000 275,000
Senior Notes due 2008.............. 7 7/8% -- 400,000 --
-------- --------
Total.................... $951,750 $560,000
======== ========
The Company has completed a series of public debt offerings since 1994.
Transaction costs in connection with the debt offerings are capitalized as
Deferred Financing Costs in the accompanying Consolidated Financial Statements
and are being amortized over the ten-year life of the related offerings.
Interest is payable semiannually at specified rates. There are no sinking fund
or mandatory redemptions of principal before the maturity dates of each
offering. The Senior Note indentures limit the Company's ability to incur
additional debt, pay dividends, sell assets and enter into certain transactions.
Senior Notes Due 2004
The Senior Notes due 2004 bear interest at 9 1/4% per year, payable
semi-annually on February 1 and August 1 each year and mature on February 1,
2004. The Senior Notes are redeemable, at the option of the Company, at any time
on or after February 1, 1999 at various redemption prices. In addition, the
Company may redeem up to $ 36.8 million of the Senior Notes from the proceeds of
any public equity offering. The effective interest rate on the $105.0 million,
after amortization of deferred financing costs, was 9.6%. Based on the traded
yield to maturity, the approximate fair market value of the Senior Notes due
2004 was $108.2 million and $108.7 million as of December 31, 1998 and 1997,
respectively.
Senior Notes Due 2006
The Senior Notes due 2006 bear interest at 10 1/2% per year, payable
semi-annually on May 15 and November 15 each year and mature on May 15, 2006.
The Senior Notes are redeemable, at the option of the Company, at any time on or
after May 15, 2001 at various redemption prices. In addition, the Company may
redeem up to $63.0 million of the Senior Notes from the proceeds of any public
equity offering. The effective interest rate on the $171.8 million, after
amortization of deferred financing costs, was 10.8%. Based on the traded yield
to maturity, the approximate fair market value of the Senior Notes due 2006 was
$188.9 million and $196.2 million as of December 31, 1998 and 1997,
respectively.
During the second and third quarter of 1998, the Company repurchased a
total of $8.3 million of the Senior Notes due 2006 and recognized an
extraordinary charge of $641,000 (net of tax benefit of $441,000). The Senior
Notes due 2006 were redeemed at a premium plus accrued interest to the date of
repurchase (see Note 12).
F-37
74
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Senior Notes Due 2007
The Senior Notes due 2007 bear interest at 8 3/4% per year, payable
semi-annually on January 15 and July 15 each year and mature on July 15, 2007.
The Senior Notes are redeemable, at the option of the Company, at any time on or
after July 15, 2002 at various redemption prices. In addition, the Company may
redeem up to $96.3 million of the Senior Notes from the proceeds of any public
equity offering.
F-38
75
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
In the second quarter of 1997, the Company executed five interest rate
hedging transactions related to debt. The notional value of the interest rate
swaps were $182.0 million and were designed to eliminate interest rate risk for
the period from May 1997 to July 1997 when the $200.0 million of 8 3/4% Senior
Notes Due 2007 were priced. These interest rate hedging transactions were
designated as a hedge of the anticipated bond offering, and the resulting $3.0
million cost resulting from the hedges is being amortized over the life of the
bonds. The effective interest rate on the $275.0 million, after amortization of
deferred financing costs, was 9.1%. Based on the traded yield to maturity, the
approximate fair market value of the Senior Notes due 2007 was $288.8 million
and $280.5 million as of December 31, 1998 and 1997, respectively.
Senior Notes Due 2008
On March 5, 1998, the Company terminated an existing forward Treasury bond
entered into in February 1998 in anticipation of the Senior Notes due 2008
offering. The Company closed its position prior to the pricing date of the debt,
which resulted in a gain of $2.3 million. The gain was deferred and is
recognized as an offset to interest expense over the remaining life of the
Senior Notes due 2008 using the effective interest method.
On March 31, 1998, the Company sold $300.0 million Senior Notes due 2008.
After deducting discounts to initial purchasers and expenses of the offering,
the net proceeds from the sale of the Senior Notes due 2008 were approximately
$293.5 million. Proceeds from Senior Notes due 2008 were used as follows: (i)
$52.8 million for the purchase of the remaining 50% interest in TCC (See Note
3), (ii) $105.3 million for the restructuring of certain gas contracts
associated with the TCC acquisition (See Note 3), (iii) $89.6 million for the
outstanding principal on the non-recourse project financing provided by The Bank
of Nova Scotia, and (iv) $38.2 million for the outstanding debt on the Bethpage
Power Plant (See Note 3). Transaction costs incurred in connection with the debt
offering were recorded as a deferred charge and are amortized over the ten-year
life of the Senior Notes due 2008 using the effective interest rate method.
Subsequent to this offering, on July 24, 1998, the Company sold $100.0
million Senior Notes due 2008. After deducting discounts to initial purchasers
and expenses of the offering, the net proceeds from the sale of the Senior Notes
due 2008 were approximately $98.8 million. With the net proceeds, the Company
has repaid in full the non-recourse project financing on the Pasadena Power
Plant of $52.1 million to ING, and has used $46.7 million for a portion of the
remaining construction costs for the Pasadena Power Plant. Transaction costs
incurred in connection with the debt offering were recorded as a deferred charge
and are amortized over the ten-year life of the Senior Notes due 2008 using the
effective interest rate method.
The Senior Notes Due 2008 bear interest at 7 7/8% per year, payable
semi-annually on April 1 and October 1 each year and mature on April 1, 2008.
The Senior Notes are not redeemable prior to maturity. The effective interest
rate on the $400.0 million, after amortization of deferred financing costs, was
8.1%. Based on the traded yield to maturity, the approximate fair market value
of the Senior Notes due 2008 was $403.0 million as of December 31, 1998.
F-39
76
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The annual principal maturities of the non-recourse project and corporate
financings as of December 31, 1998 are as follows (in thousands):
1999........................................................ $ 5,450
2000........................................................ 6,860
2001........................................................ 6,860
2002........................................................ 7,060
2003........................................................ 7,990
Thereafter.................................................. 1,037,170
----------
Total............................................. $1,071,390
==========
8. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
On May 15, 1998, the Company replaced its $50.0 million credit facility
with a $100.0 million credit facility, which has a three-year term expiring in
May 2001. The Company's $100.0 million credit facility is available through a
consortium of commercial lending institutions with The Bank of Nova Scotia as
agent. A maximum of $50.0 million of the credit facility may be allocated to
letters of credit. At December 31, 1998, the Company had no borrowings and $26.4
million of letters of credit outstanding under the credit facility. This amount
includes $8.2 million to secure performance of the Magic Valley and Pasadena
Power Plants. Borrowings bear interest at The Bank of Nova Scotia's base rate
plus an applicable margin or at LIBOR plus an applicable margin. Interest is
paid on the last day of each interest period for such loans, at least quarterly.
The credit agreement specifies that the Company maintain certain covenants, with
which the Company was in compliance, as of December 31, 1998. Commitment fees
related to this line of credit are charged based on 0.375% of committed unused
credit.
At December 31, 1998, the Company had a loan facility with Union Bank with
available borrowings totaling $1.1 million. As of December 31, 1998, the Company
had no borrowings and $74,196 of letters of credit outstanding.
At December 31, 1998, the Company had a $12.0 million letter of credit
outstanding with The Bank of Nova Scotia to secure performance of the Clear Lake
Power Plant.
9. PROVISION FOR INCOME TAXES
The components of the deferred tax liability, net as of December 31, 1998
and 1997 are as follows (in thousands):
1998 1997
--------- ---------
Expenses deductible in a future period............... $ 3,721 $ 4,122
Net operating loss and credit carryforwards.......... 19,550 20,260
Other differences.................................... 4,340 2,524
--------- ---------
Deferred tax assets................................ 27,611 26,906
--------- ---------
Property differences................................. (178,171) (156,526)
Difference in taxable income and income from
investments recorded on the equity method.......... (3,796) (5,798)
Other differences.................................... (5,432) (6,632)
--------- ---------
Deferred tax liabilities........................... (187,399) (168,956)
--------- ---------
Net deferred tax liability...................... $(159,788) $(142,050)
========= =========
F-40
77
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The net operating loss and credit carryforwards consist of federal net
operating loss carryforwards which expire 2005 through 2010 and federal and
state alternative minimum tax credit carryforwards which can be carried forward
indefinitely. At December 31, 1998, the federal and state net operating loss
carryforwards have been fully utilized. At December 31, 1998, federal and state
alternative minimum tax credit carryforwards were approximately $15.5 million
and $4.0 million, respectively. In 1998, and 1997, the Company decreased its
deferred income tax liability by $4.8 million and $2.1 million, respectively, to
reflect the decrease in the California tax rate due to the Company's expansion
into states other than California. Realization of the deferred tax assets and
federal net operating loss carryforwards is dependent, in part, on generating
sufficient taxable income prior to expiration of the loss carryforwards. 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 carry-
forward period are reduced.
The provision for income taxes for the years ended December 31, 1998, 1997
and 1996 consists of the following (in thousands):
1998 1997 1996
------- ------- ------
Current:
Federal...................................... $ 1,582 $ 1,892 $5,671
State........................................ 277 917 1,805
Deferred:
Federal...................................... 26,830 14,989 3,890
State........................................ 1,772 2,897 (801)
Adjustment in state tax rate (net of
federal benefit)........................ (4,826) (2,113) (769)
Revision in prior years' tax estimates.... 1,419 (122) (732)
------- ------- ------
Total provision...................... $27,054 $18,460 $9,064
======= ======= ======
The Company's effective rate for income taxes for the years ended December
31, 1998, 1997 and 1996 differs from the United States statutory rate, as
reflected in the following reconciliation.
1998 1997 1996
---- ---- ----
United States statutory tax rate....................... 35.0% 35.0% 35.0%
State income tax, net of federal benefit............... 3.8 5.0 6.0
Depletion allowance.................................... (1.5) (2.1) (2.3)
Effect of change in state tax rates, net of federal
benefit.............................................. -- -- (3.0)
Decrease in California deferred tax due to Company's
expansion into other states, net of federal
benefit.............................................. -- (4.1) --
Revision in prior years' tax estimates................. -- -- (2.6)
Other, net............................................. (0.4) 0.9 (0.4)
---- ---- ----
Effective income tax rate......................... 36.9% 34.7% 32.7%
==== ==== ====
10. EMPLOYEE BENEFIT PLANS
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-
F-41
78
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
sharing contribution. Employer profit-sharing contributions in 1998, 1997 and
1996 totaled $829,000, $588,000 and $485,000, respectively.
1996 Employee Stock Purchase Plan
The Company adopted the 1996 Employee Stock Purchase Plan ("ESPP") in July
1996. Eligible employees may purchase up to 275,000 shares of common stock at
semi-annual intervals through periodic payroll deductions. Purchases are limited
to 15 percent of an employee's eligible compensation, up to a maximum of $25,000
per year. Shares are purchased on January 31 and July 31 of each year. Under the
ESPP, 67,086 shares were issued at a weighted average fair value of $13.79 per
share in 1998. In January 1999, employees participating in the ESPP purchased an
additional 42,216 shares at a weighted average fair value of $37.00 per share.
The purchase price is 85% of the lower of (i) the fair market value of the
common stock on the participant's entry date into the offering period, or (ii)
the fair market value on the semi-annual purchase date.
1996 Stock Incentive Plan
The Company adopted the 1996 Stock Incentive Plan ("SIP") in September
1996. The SIP succeeded the Company's previously adopted stock option program.
The Company accounts for the SIP under Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" under which no compensation cost
has been recognized. Had compensation cost for the SIP been determined
consistent with the methodology of SFAS No. 123, "Accounting for Stock-Based
Compensation", the Company's net income and earnings per share would have been
reduced to the following pro forma amounts (in thousands, except per share
amounts):
1998 1997 1996
------- ------- -------
Net income...................... As reported $45,678 $34,699 $18,692
Pro Forma 43,760 33,528 18,145
Earnings per share data:
Basic earnings per share........ As reported $ 2.27 $ 1.74 $ 1.45
Pro Forma 2.17 1.68 1.41
Diluted earnings per share...... As reported 2.16 1.65 1.26
Pro Forma 2.07 1.60 1.22
The fair value of options granted in 1998, 1997 and 1996 was $7.22, $10.28
and $3.29 on the date of grant using the Black-Scholes option pricing model with
the following weighted-average assumptions: expected dividend yields of 0%,
expected volatility of 35%, 44%, and 27% for 1998, 1997 and 1996, risk-free
interest rates of 5.25%, 5.8%, and 6.2% for 1998, 1997 and 1996, respectively,
expected lives of 7 years for 1998 and 1997 and 3 years for 1996.
Because the SFAS No. 123 methodology of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in future years. The
Company may grant options for up to 4,440,899 shares under the SIP. As of
December 31, 1998, the Company had granted options to purchase 2,884,440 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
F-42
79
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
four years and expire after 10 years. Changes in options outstanding, granted,
exercisable and cancelled by the Company during the years 1998, 1997, and 1996,
whether under the option or purchase plan were as follows:
AVAILABLE FOR WEIGHTED
OPTION OR NUMBER OF AVERAGE
AWARD SHARES EXERCISE PRICE
------------- --------- --------------
Beginning as of January 1, 1996........ 742,412 1,854,511 $2.34
Additional shares reserved........... 1,444,935 -- --
Granted........................... (547,579) 547,579 8.71
Exercised......................... -- (5,000) 1.85
Cancelled......................... 56,796 (56,796) 7.90
--------- --------- -----
Outstanding December 31, 1996.......... 1,696,564 2,340,294 3.69
Granted.............................. (394,217) 394,217 18.31
Exercised............................ -- (163,156) 1.33
Cancelled............................ 51,552 (51,552) 8.55
--------- --------- -----
Outstanding December 31, 1997.......... 1,353,899 2,519,803 6.03
Additional shares reserved........... 399,041 -- --
Granted........................... (420,725) 420,725 17.04
Exercised......................... -- (33,790) 2.95
Cancelled......................... 22,298 (22,298) 15.63
--------- --------- -----
Outstanding December 31, 1998.......... 1,354,513 2,884,440 $7.59
========= ========= =====
Options exercisable:
December 31, 1996...................... 1,445,746 $1.71
December 31, 1997...................... 1,635,469 3.23
December 31, 1998...................... 1,926,805 4.39
On May 1, 1998, the Company granted CCNG Investments, L.P. ("CCNG") options
to purchase 1.1 million shares of the Company's common stock ("Stock Purchase
Agreement"). Under the terms of the Stock Purchase Agreement, CCNG had the
one-time right prior to September 28, 1998, to elect to purchase from the
Company up to 1.0 million shares of the Company's common stock, $0.001 par
value. CCNG did not exercise any part of this right. Additionally, prior to
December 31, 1998, CCNG had the one-time right to purchase from the Company up
to 50,000 shares of common stock at a price of $17 7/8 per share. On December
31, 1998, CCNG notified the Company of its intent to exercise 50,000 shares on
January 4, 1999, of which the Company has determined to be immaterial.
F-43
80
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The following tables summarizes information concerning outstanding and
exercisable options at December 31, 1998:
OUTSTANDING OPTIONS
----------------------------------------------- OPTIONS EXERCISABLE
WEIGHTED AVERAGE -----------------------------
REMAINING WEIGHTED WEIGHTED
RANGE OF NUMBER OF CONTRACTUAL AVERAGE NUMBER OF AVERAGE
EXERCISE PRICES SHARES LIFE IN YEARS EXERCISE PRICE SHARES EXERCISE PRICE
- --------------- --------- ---------------- -------------- --------- ----------------
$ 0.50 -- $ 0.50....... 831,420 4.00 $ 0.50 831,420 $ 0.50
$ 1.85 -- $ 1.85....... 104,693 4.25 1.85 104.693 1.85
$ 4.57 -- $ 4.57....... 284,758 5.75 4.57 284,758 4.57
$ 4.91 -- $ 4.91....... 398,270 7.00 4.91 298,696 4.91
$ 5.17 -- $ 6.83....... 9,542 8.86 5.40 9,542 5.40
$ 8.57 -- $ 8.57....... 469,057 8.00 8.57 234,021 8.57
$15.50 -- $16.00....... 20,000 8.36 15.75 20,000 15.75
$17.20 -- $17.20....... 362,500 9.18 17.20 -- --
$17.56 -- $22.44....... 404,200 8.33 18.35 143,675 18.83
--------- --------- --------- --------- ---------
Total........ 2,884,440 6.55 $ 7.59 1,926,805 $ 4.39
========= ========= ========= ========= =========
11. STOCKHOLDERS' EQUITY
Preferred Stock and Preferred Share Purchase Rights
On June 5, 1997, the Board of Directors adopted a Stockholders Rights Plan
("Rights Plan") to strengthen the Board of Directors ability to protect the
Company's stockholders. The Rights Plan is designed to protect against abusive
or coercive takeover tactics that are not in the best interests of the Company
and its stockholders. To implement the Rights Plan, the Board of Directors
declared a dividend of one preferred share purchase right (a "Right") for each
outstanding share of common stock, par value $0.001 per share, held on record as
of June 18, 1997, and directed the issuance of one Right with respect to each
share of Common Stock that shall become outstanding between the Record Date and
the Distribution Date. On December 31, 1998, there were 20,161,581 Rights
outstanding. Each Right initially represents a contingent right to purchase,
under certain circumstances, one one-thousandth of a share (a "Unit") of Series
A Junior Participating Preferred Stock, par value $0.001 per share (the
"Preferred Stock"), of the Company at a price of $80.00 per Unit, subject to
adjustment. The Rights become exercisable and trade independently from the
Company's common stock upon the public announcement of the acquisition by a
person or group of 15% or more of the Company's common stock, or ten days after
commencement of a tender or exchange offer that would result in the acquisition
of 15% or more of the Company's common stock. Each Unit of Preferred Stock
purchased upon exercise of the Rights will be entitled to a dividend equal to
any dividend declared per share of common stock and will have one vote, voting
together with the common stock. In the event of liquidation, each share of
Preferred Stock will be entitled to any payment made per share of common stock.
If the Company is acquired in a merger or other business combination
transaction after a person or group has acquired 15% or more of the Company's
common stock, each Right will entitle its holder to purchase at the Right's
exercise price a number of the acquiring company's common shares having a market
value of twice such exercise price. In addition, if a person or group acquires
15% or more of the Company's common stock, each Right will entitle its holder
(other than the acquiring person or group) to purchase, at the Right's exercise
price, a number of fractional shares of the Company's Preferred Stock or shares
of common stock having a market value of twice such exercise price.
F-44
81
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The Rights expire June 18, 2007, unless redeemed earlier by the Company's
Board of Directors. The Board of Directors can redeem the Rights at a price of
$0.01 per Right at any time before the Rights become exercisable, and thereafter
only in limited circumstances.
12. EARNINGS PER SHARE
Basic earnings per common share were computed by dividing net income by the
weighted average number of common shares outstanding for the period. The
dilutive effect of the potential exercise of outstanding options to purchase
shares of common stock is calculated using the treasury stock method. The
reconciliation of basic earnings per common share to diluted earnings per share
is shown in the following table (dollars in thousands except share data).
YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------------------
1998 1997 1996
------------------------- ------------------------ ------------------------
NET NET NET
INCOME SHARES EPS INCOME SHARES EPS INCOME SHARES EPS
------- ------ ------ ------- ------ ----- ------- ------ -----
BASIC EARNINGS PER COMMON SHARE:
Income before extraordinary
charge....................... $46,319 20,121 $ 2.30 $34,699 19,946 $1.74 $18,692 12,903 $1.45
Extraordinary charge net of tax
benefit of $441.............. 641 (0.03) -- -- -- --
------- ------ ------ ------- ------ ----- ------- ------ -----
Net income..................... $45,678 20,121 $ 2.27 $34,699 19,946 $1.74 $18,692 12,903 $1.45
======= ====== ====== ======= ====== ===== ======= ====== =====
Common shares issuable upon
exercise of stock options
using treasury stock
method....................... 1,043 1,070 1,976
------ ------ ------
DILUTED EARNINGS PER COMMON
SHARE:
Income before extraordinary
charge....................... $46,319 21,164 $ 2.19 $34,699 21,016 $1.65 $18,692 14,879 $1.26
Extraordinary charge net of tax
benefit of $441.............. 641 (0.03) -- -- -- --
------- ------ ------ ------- ------ ----- ------- ------ -----
Net income..................... $45,678 21,164 $ 2.16 $34,699 21,016 $1.65 $18,692 14,879 $1.26
======= ====== ====== ======= ====== ===== ======= ====== =====
In 1998, the Company recognized a $641,000 extraordinary charge (net of tax
benefit of $441,000), for the repurchase of $8.3 million of the 10 1/2% Senior
Notes Due 2006. The notes were redeemed at a premium plus accrued interest to
the date of repurchase.
Unexercised employee stock options to purchase 385,000 shares of the
Company's common stock during the year ended December 31, 1997 were not included
in the computation of diluted shares outstanding because such inclusion would be
anti-dilutive.
13. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from three
sources -- Pacific Gas & Electric Company ("PG&E"), Texas Utilities Electric
Company ("TUEC"), and SMUD.
F-45
82
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Revenues earned from these sources for the years ended, December 31, 1998,
1997 and 1996 were as follows (in thousands):
1998 1997 1996
-------- -------- --------
REVENUES:
PG&E....................................... $222,593 $221,457 $183,531
TUEC....................................... 128,724 -- --
SMUD....................................... 11,353 13,223 14,609
Accounts receivable at December 31, 1998, and 1997 were as follows (in
thousands):
1998 1997
------- -------
ACCOUNTS RECEIVABLE:
PG&E..................................................... $25,186 $29,631
TUEC..................................................... 15,052 --
SMUD..................................................... 575 1,019
14. COMMITMENTS AND CONTINGENCIES
Production Royalties and Leases -- The Company is committed under several
geothermal leases and right-of-way, easement and surface agreements. The
geothermal leases generally provide for royalties based on production revenue
with reductions for property taxes paid. The right-of-way, easement and surface
agreements are based on flat rates and are not material. Under the terms of
certain geothermal leases, royalties accrue at rates ranging from 7% to 12.5% of
steam and effluent revenue. Certain properties also have net profits and
overriding royalty interests ranging from approximately 1.45% to 28%, which are
in addition to the land royalties. Most lease agreements contain clauses
providing for minimum lease payments to lessors if production temporarily ceases
or if production falls below a specified level.
Expenses under these agreements for the years ended December 31, 1998,
1997, and 1996 are (in thousands):
1998 1997 1996
------- ------- -------
Production Royalties.......................... $10,713 $10,803 $10,793
Lease payments................................ 144 222 246
Natural Gas Purchases -- The Company enters into short-term gas purchase
contracts with third parties to supply gas to its gas-fired cogeneration
projects.
Cogeneration Facilities Operating and Land Leases -- The Company entered
into long-term operating leases in June 1995, April 1996 and August 1998 for its
Watsonville, King City, and Greenleaf cogeneration
F-46
83
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
facilities and the land lease for the Pasadena Power Plant. Future minimum lease
payments under these leases are as follows (in thousands):
WATSONVILLE KING CITY GREENLEAF PASADENA
----------- --------- --------- --------
1999............................ $ 2,905 $ 19,567 $ 8,988 $ 125
2000............................ 2,905 20,254 8,991 125
2001............................ 2,905 21,015 9,070 250
2002............................ 2,905 21,848 8,990 250
2003............................ 2,905 22,781 8,994 250
Thereafter...................... 18,588 143,986 80,509 3,750
------- -------- -------- ------
Total................. $33,113 $249,451 $125,542 $4,750
======= ======== ======== ======
In 1998, 1997 and 1996, rent expense for cogeneration facilities operating
leases amounted to $15.7 million, $16.6 million and $12.0 million, respectively.
The Watsonville operating lease provides for additional contingent rents payable
during the period from July through December. Contingent rent expense for 1998,
1997 and 1996 amounted to $1.5 million, $864,000 and $671,000, respectively.
The King City operating lease commitment is supported by $90.7 million of
collateral securities consisting of investment grade and U.S. Treasury
securities that mature serially in amounts equal to a portion of the semi-annual
lease payment (see Note 2).
In August 1998, the Company entered into a sales and leaseback transaction
for certain plant and equipment of its Greenleaf 1 & 2 Power Plants, two 49.5
megawatt gas-fired cogeneration facilities located in Sutter County, California,
for a net book value of $108.6 million. Under the terms of the agreement, the
Company received approximately $559,000 for the sale of its rights, title and
interest in the stock of Calpine Greenleaf Corporation and transferred all of
its non-recourse financing of $71.6 million (see Note 6) and deferred taxes of
$21.4 million. A loss of $15.6 million was recorded on the balance sheet and is
being amortized over the term of the lease through June 2014.
Office and Equipment Leases -- The Company leases its corporate office and
regional offices in Boston, Massachusetts, Houston, Texas, Pleasanton,
California, and Santa Rosa, California under noncancellable operating leases
expiring through 2002. Future minimum lease payments under these leases are as
follows (in thousands):
1999........................................................ $2,150
2000........................................................ 2,154
2001........................................................ 1,588
2002........................................................ 1,025
2003........................................................ 705
Thereafter.................................................. --
------
Total............................................. $7,622
======
Lease payments are subject to adjustments for the Company's pro rata
portion of annual increases or decreases in building operating costs. In 1998,
1997 and 1996 rent expense for noncancellable operating leases amounted to $1.2
million, $1.2 million and $1.0 million, respectively.
Capital expenditures -- At December 31, 1998, the Company is under contract
with Siemens Westinghouse Power Corporation for a total of $322.2 million for
the purchase of six turbines related to three power
F-47
84
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
development projects. Approximate payments related to these turbines are $231.7,
$85.3 and $5.2 million in 1999, 2000, and 2001, respectively.
Litigation
Legal Matters -- On September 30, 1997, a lawsuit was filed by Indeck North
American Power Fund ("Indeck") in the Circuit Court of Cook County, Illinois
against Norweb plc. and certain other parties, including the Company. Some of
Indeck's claims relate to Calpine Gordonsville, Inc.'s acquisition of a 50%
interest in Gordonsville Energy L.P. from Northern Hydro Limited and Calpine
Auburndale, Inc.'s acquisition of a 50% interest in Auburndale Power Plant
Partners Limited Partnership from Norweb Power Services (No. 1) Limited. Indeck
is claiming that Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the
Company tortiously interfered with Indeck's contractual rights to purchase such
interests and conspired with other parties to do so. Indeck is seeking $25.0
million in compensatory damages, $25.0 million in punitive damages, and the
recovery of attorneys' fees and costs. In July 1998, the court granted motions
to dismiss, without prejudice, the claims against Calpine Gordonsville, Inc. and
Calpine Auburndale, Inc. In August 1998, Indeck filed an amended complaint and
the defendants filed motions to dismiss. A hearing on those motions is scheduled
for the end of February 1999. The Company is unable to predict the outcome of
these proceedings, but does not believe this will have a material adverse effect
on the Consolidated Financial Statements.
There is currently a dispute between Texas-New Mexico Power Company ("TNP")
and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear
Lake Power Plant, regarding certain costs and other amounts that TNP has
withheld from payments due under the power sales agreement from August 1997
until October 1998. TNP has withheld approximately $450,000 per month related to
transmission charges. In October 1997, CLC filed a petition for declaratory
order with the Texas Public Utilities Commission ("Texas PUC") requesting a
declaration that TNP's withholding is in error, which petition is currently
pending. Also, as of December 31, 1998, TNP has withheld approximately $7.7
million of standby power charges. In addition to the Texas PUC petition, CLC
filed an action in Texas courts on October 2, 1997, alleging TNP's breach of the
power sales agreement and is seeking refund of the standby charges. In October
1998, TNP and CLC reached an agreement in principle to settle all outstanding
disputes. The parties are currently finalizing the documentation of the
settlement which must be approved by the Texas PUC. Both the Texas PUC action
and the court action have been put on hold pending completion of the settlement.
The Company does not believe this has a material adverse effect on the
consolidated financial statements.
An action was filed against Lockport Energy Associates, L.P. ("LEA") and
the New York Public Service Commission ("NYPSC") in August 1997 by New York
State Electricity and Gas Company ("NYSEG") in the Federal District Court for
the Northern District of New York. NYSEG has requested the Court to direct NYPSC
and the Federal Energy Regulatory Commission (the "FERC") to modify contract
rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a
cross-claim alleging that the FERC violated the Public Utility Regulatory
Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by failing
to reform the NYSEG contract that was previously approved by the NYPSC. Although
it is unable to predict the outcome of this case, in any event, the Company
retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase
the Company's interest in the Lockport Power Plant for $18.9 million, less
equity distributions received by the Company, at any time before December 19,
2001.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. The Company does not expect that the
outcome of these proceedings will have a material adverse effect on the
Company's financial position or results of operations, although no assurance can
be given in this regard.
F-48
85
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
15. SUBSEQUENT EVENTS
On January 4, 1999, the Company entered into a credit agreement with ING to
provide $265.0 million of non-recourse project financing for the Pasadena
expansion, a 510 megawatt gas-fired cogeneration project.
16. 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 of
operations under the terms of certain power sales agreements, 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.
The Company's common stock has been traded on the New York stock exchange
since September 19, 1996. There were 50 common stockholders of record at
December 31, 1998. No dividends were paid for the years ended December 31, 1998
and 1997.
F-49
86
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
QUARTER ENDED
---------------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 30
----------- ------------ -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1998
Total revenue................................ $173,033 $186,173 $141,597 $55,145
Gross profit................................. 50,935 69,069 44,841 15,776
Income from operations....................... 40,262 59,959 37,596 8,859
Income before extraordinary charge........... 14,033 23,415 11,928 (3,057)
Extraordinary charge......................... -- 339 302 --
Net income (loss)............................ 14,033 23,076 11,626 (3,057)
Basic earnings per common share:
Income before extraordinary charge......... $ 0.70 $ 1.16 $ 0.59 $ (0.15)
Extraordinary charge....................... -- (0.01) (0.01) --
Net income................................. 0.70 1.15 0.58 (0.15)
Diluted earnings per common share:
Income before extraordinary charge......... $ 0.66 $ 1.11 $ 0.56 $ (0.15)
Extraordinary charge....................... -- (0.02) (0.01) --
Net income................................. 0.66 1.09 0.55 (0.15)
Common stock price per share
High....................................... $ 27.63 $ 21.50 $ 21.25 $ 18.50
Low........................................ 17.19 17.13 17.25 12.75
1997
Total revenue................................ $ 76,441 $ 92,905 $ 67,744 $39,231
Gross profit................................. 34,067 49,766 30,538 8,642
Income from operations....................... 27,154 43,384 24,379 2,270
Net income (loss)............................ 10,192 19,147 9,400 (4,040)
Basic earnings per common share.............. $ 0.51 $ 0.96 $ 0.47 $ (0.20)
Diluted earnings per common share............ 0.48 0.91 0.45 (0.20)
Common stock price per share
High....................................... $ 21.25 $ 22.94 $ 20.88 $ 22.75
Low........................................ 12.38 16.50 15.75 17.13
F-50
87
CALPINE CORPORATION AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31, 1998
ADDITIONS
----------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COSTS AND OTHER END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ----------- ------------ ---------- ---------- ---------- ----------
Reserve for capitalized costs...... $ 238 $ -- $ -- $ -- $ 238
Allowance for uncollectible
accounts......................... 238 -- -- -- 238
FOR THE YEAR ENDED DECEMBER 31, 1997
ADDITIONS
----------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COSTS AND OTHER END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ----------- ------------ ---------- ---------- ---------- ----------
Reserve for capitalized costs...... $1,838 $ -- $ -- $(1,600) $ 238
Allowance for uncollectible
accounts......................... 238 -- -- -- 238
FOR THE YEAR ENDED DECEMBER 31, 1996
ADDITIONS
----------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COSTS AND OTHER END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- ----------- ------------ ---------- ---------- ---------- ----------
Reserve for capitalized costs...... $1,838 $ -- $ -- $ -- $1,838(1)
Allowance for uncollectible
accounts......................... 238 -- -- -- 238
- ---------------
(1) Provision for write-off of project development expenses.
F-51
88
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, 1998 and 1997, and
the related consolidated statements of income, changes in partners' deficit, and
cash flows for each of the three years ended December 31, 1998, 1997 and 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, 1998 and 1997, and
the results of their operations and cash flows for each of the three years ended
December 31, 1998, 1997 and 1996 in conformity with generally accepted
accounting principles.
MOSS ADAMS LLP
Everett, Washington
January 20, 1999
F-52
89
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEET
ASSETS
DECEMBER 31,
----------------------------
1998 1997
------------ ------------
Current assets
Cash and cash equivalents................................. $ 547,444 $ 208,776
Current portion of restricted cash and cash equivalents... 8,557,460 6,094,892
Accounts receivable....................................... 5,132,367 4,502,790
Spare parts inventory..................................... 3,220,681 41,095
Prepaid expenses.......................................... 134,714 139,953
------------ ------------
Total current assets.............................. 17,592,666 10,987,506
Restricted cash and cash equivalents, net of current
portion................................................... 11,949,849 6,214,000
Property, plant and equipment, at cost, net................. 86,471,056 90,459,854
Other assets................................................ 10,855,289 10,819,238
------------ ------------
Total assets...................................... $126,868,860 $118,480,598
============ ============
LIABILITIES AND PARTNERS' DEFICIT
Current liabilities
Accounts payable and accrued liabilities.................. $ 7,123,030 $ 2,780,693
Related party distributions and payables
Calpine Corporation payable............................ 508,682 490,676
National Energy Systems Company payable................ 2,345 1,415
Partner distributions.................................. 2,922,603 1,736,612
Current portion of long-term debt......................... 5,400,000 4,200,000
------------ ------------
Total current liabilities......................... 15,956,660 9,209,396
Long-term debt, net of current portion...................... 138,127,454 129,200,004
Future removal and site restoration costs................... 893,185 731,184
Deferred income taxes....................................... 788,356 396,926
Commitments................................................. -- --
Partners' deficit........................................... (28,896,795) (21,056,912)
------------ ------------
Total liabilities and partners' deficit........... $126,868,860 $118,480,598
============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-53
90
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31,
--------------------------------------------
1998 1997 1996
------------ ------------ ------------
Revenues
Power sales.................................... $ 46,911,259 $ 38,309,558 $ 43,488,465
Natural gas sales, net......................... 2,539,137 2,483,862 434,611
Other.......................................... 141,750 -- 169,146
------------ ------------ ------------
Total revenues......................... 49,592,146 40,793,420 44,092,222
------------ ------------ ------------
Costs and expenses
Operating and production costs................. 19,281,670 11,211,812 16,852,253
Depletion, depreciation and amortization....... 6,520,057 6,898,111 5,702,310
General and administrative..................... 2,052,942 1,949,365 2,481,470
------------ ------------ ------------
Total costs and expenses............... 27,854,669 20,059,288 25,036,033
------------ ------------ ------------
Income from operations........................... 21,737,477 20,734,132 19,056,189
------------ ------------ ------------
Other income (expense)
Interest income................................ 692,885 1,190,133 406,537
Interest expense............................... (11,333,186) (10,782,823) (10,678,618)
Other expense.................................. (1,863,991) (68,258) (133,958)
------------ ------------ ------------
Total other expense.................... (12,504,292) (9,660,948) (10,406,039)
------------ ------------ ------------
Income before benefit (provision) for income
taxes.......................................... 9,233,185 11,073,184 8,650,150
Income taxes benefit (provision)................. 471,210 (525,642) 155,951
------------ ------------ ------------
Net income............................. $ 8,761,975 $ 11,598,826 $ 8,494,199
============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-54
91
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' DEFICIT
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Partners' Deficit, December 31, 1995........................ $ (574,916)
Net income.................................................. 8,494,199
Distributions to partners................................... (4,297,970)
------------
Partners' Equity, December 31, 1996......................... 3,621,313
Net income.................................................. 11,598,826
Distributions to partners................................... (36,277,051)
------------
Partners' Deficit, December 31, 1997........................ (21,056,912)
Net income.................................................. 8,761,975
Distributions to partners................................... (16,601,858)
------------
Partners' Deficit, December 31, 1998........................ $(28,896,795)
============
The accompanying notes are an integral part of these consolidated financial
statements.
F-55
92
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31,
--------------------------------------------
1998 1997 1996
------------ ------------ ------------
Cash flows from operating activities
Net income (loss).............................. $ 8,761,975 $ 11,598,826 $ 8,494,199
Adjustments to reconcile net income (loss) to
net cash from operating activities
Depletion, depreciation and amortization.... 6,520,057 6,898,111 6,571,522
Loss on disposal of fixed assets............ 1,847,741 -- --
Deferred income taxes....................... 391,430 (591,474) 80,600
Change in operating assets and liabilities
Accounts receivable....................... (629,577) 102,345 (1,514,922)
Spare parts inventory..................... (3,179,586) (1,458) --
Prepaid expenses.......................... 5,239 40,540 2,698
Accounts payable and accrued
liabilities............................ 4,504,338 (155,930) 1,114,029
Related party payables.................... 18,936 14,211 (437,524)
------------ ------------ ------------
Net cash from operating activities..... 18,240,553 17,905,171 14,310,602
------------ ------------ ------------
Cash flows from investing activities
Decrease (increase) in restricted cash and cash
equivalents................................. (8,198,417) 9,144,876 (10,498,126)
Acquisition of property, plant and equipment... (3,159,051) (3,772,579) (913,970)
Increase in other assets....................... (1,256,000) (1,727,958) --
------------ ------------ ------------
Net cash from investing activities..... (12,613,468) 3,644,339 (11,412,096)
------------ ------------ ------------
Cash flows from financing activities
Repayment of long-term debt.................... (4,200,300) (3,600,000) (2,000,000)
Proceeds from long-term debt................... 14,327,750 20,000,000 --
Distributions to partners...................... (15,415,867) (38,057,930) (780,479)
------------ ------------ ------------
Net cash from financing activities..... (5,288,417) (21,657,930) (2,780,479)
------------ ------------ ------------
Net increase (decrease) in cash and cash
equivalents.................................... 338,668 (108,420) 118,027
Cash and cash equivalents, beginning of year..... 208,776 317,196 199,169
------------ ------------ ------------
Cash and cash equivalents, end of year........... $ 547,444 $ 208,776 $ 317,196
============ ============ ============
Supplementary disclosure of cash flow information
Cash paid for interest during the year......... $ 11,333,186 $ 10,782,823 $ 10,678,618
============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-56
93
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General -- Sumas Cogeneration Company, L.P. (the Partnership) is a Delaware
limited partnership formed in 1991 between Sumas Energy, Inc. (SEI), the general
partner which currently holds a 50% interest in the profits and losses of the
Partnership, and Whatcom Cogeneration Partners, L.P. (Whatcom), the sole limited
partner which holds the remaining 50% Partnership interest. In addition, Whatcom
is entitled certain additional distribution amounts through December 31, 2000.
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) whose functional currency is deemed to be in U.S. dollars. All
intercompany profits, transactions and balances have been eliminated in
consolidation.
The Partnership owns and operates an electrical generation facility (the
Generation Facility) in Sumas, Washington. The Generation Facility is a natural
gas-fired combined cycle electrical generation plant which has a nameplate
capacity of approximately 125 megawatts. Commercial operation of the Generation
Facility commenced in April 1993. The Generation Facility includes a lumber dry
kiln facility and a 3.5 mile private natural gas pipeline.
ENCO owns and operates a portfolio of natural gas reserves in British
Columbia and Alberta, Canada, which provide a dedicated fuel supply for the
Generation Facility (collectively, the Project). ENCO produces and supplies
natural gas to the Generation Facility and to third parties. Prior to November
1, 1998, the Generation Facility also received a portion of its fuel under
contracts with third parties.
The Partnership produces and sells its entire electrical output to Puget
Sound Energy, Inc. (Puget) under a 20-year electricity sales contract. The
electricity sales contract provides for the sale of electrical output at stated
prices through 2012. The electricity sales contract also provides for the
electrical output of the Generation Facility to be displaced when the cost of
Puget's replacement power is less than the Company's incremental power
generation costs. The Company receives a share of the net savings from
displacement. During 1998 and 1997, the Generation Facility was displaced for
approximately one month and six months, respectively. Under the electricity
sales contract, the Partnership is required to be certified as a qualifying
cogeneration facility as established by the Public Utility Regulatory Policy Act
of 1978, as amended, and as administered by the Federal Energy Regulatory
Commission.
The Generation Facility produced and sold kilowatt hours of electricity to
Puget as follows:
YEAR ENDED DECEMBER 31, KILOWATT HOURS
----------------------- --------------
1998........................................ 915,227,280
1997........................................ 439,370,000
1996........................................ 1,031,900,000
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.
The Partnership -- SEI assigned all its rights, title, and interest in the
Project, including the Puget contract, to the Partnership in exchange for its
Partnership interest. During 1998, the Partnership Agreement was amended to
reallocate distributions among the partners. SEI and Whatcom are both currently
entitled to a 50% interest in the profits, losses and cash flow of the
Partnership. In addition, Whatcom is entitled to an additional allocation of
profits, losses and cash flows for the period through December 31, 2000. After
F-57
94
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Whatcom has received cumulative distributions representing its target return,
SEI's share of operating distributions will increase to 99.9% and Whatcom's
share of operating distributions will decrease to 0.1%.
Distributions -- Distributions of operating cash flows are permitted
quarterly after required deposits are made and minimum cash balances are met,
and are subject to certain other restrictions. For the year ended December 31,
1998, distributions totaling $16,601,858 were paid or accrued. On January 29,
1999, the December 31, 1998 accrued distributions in the amount of $2,922,603
will be paid.
Revenue recognition -- Revenue from the sale of electricity is recognized
based on kilowatt hours generated and delivered to Puget at contractual rates.
Revenue from displacement is recognized in the period to which the displacement
relates. Revenue from the sale of natural gas is recognized based on volumes
delivered to customers at contractual delivery points and rates. The costs
associated with the generation of electricity and the delivery of gas, including
operating and maintenance costs, gas transportation and royalties, are
recognized in the same period in which the related revenue is earned and
recorded.
Gas acquisition and development costs -- ENCO follows the full cost method
of accounting for gas acquisition and development expenditures, wherein all
costs related to the development of gas reserves in Canada are initially
capitalized. Costs capitalized include land acquisition costs, geological and
geophysical expenditures, rentals on undeveloped properties, cost of drilling
productive and nonproductive wells, and well equipment. Gains or losses are not
recognized upon disposition or abandonment of natural gas properties unless a
disposition or abandonment would significantly alter the relationship between
capitalized costs and proven reserves.
All capitalized costs of gas properties, including the estimated future
costs to develop proven reserves, are depleted using the unit-of-production
method based on estimated proven gas reserves as determined by independent
engineers. ENCO has not assigned any value to its investment in unproven gas
properties and, accordingly, no costs have been excluded from capitalized costs
subject to depletion.
Costs subject to depletion under the full cost method include estimated
future costs of dismantlement and abandonments of ENCO of $3,327,000 in 1998,
$3,560,000 in 1997 and $3,718,000 in 1996. 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 $162,000 in 1998, $168,000 in 1997 and $177,000 in 1996, are included
in depletion expense.
Capitalized costs are subject to a ceiling test which limits such costs to
the aggregate of the net present value of the estimated future cash flows from
the related proven gas reserves. The ceiling test calculation is made by
estimating the future net cash flows, based on current economic operating
conditions, plus the lower of cost or fair market value of unproven reserves,
and discounting those cash flows at an annual rate of 10%.
Joint venture accounting -- A significant portion of ENCO's natural gas
production activities are conducted jointly with others and, accordingly, these
consolidated financial statements reflect only ENCO's proportionate interest in
such activities.
Foreign exchange gains and losses -- Foreign exchange gains and losses as a
result of translating Canadian dollar transactions and Canadian dollar
denominated cash, accounts receivable and accounts payable transactions are
recognized in the statement of income.
Cash and cash equivalents -- For purposes of the statement of cash flows,
cash and cash equivalents consist of cash and short-term investments in highly
liquid instruments such as certificates of deposit, money market accounts and
U.S. treasury bills with an original maturity of three months or less.
Concentration of credit risk -- Financial instruments, which potentially
subject the Company to concentrations of credit risk, consist primarily of cash
and short-term investments in highly liquid instruments such as
F-58
95
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
certificates of deposit, money market accounts and U.S. treasury bills with
maturities of three months or less, and accounts receivable. The Company's cash
and cash equivalents are primarily held with two financial institutions.
Accounts receivable are primarily due from Puget.
Spare parts inventory -- Spare parts inventory includes major components of
plant and equipment which are expected to be utilized in the normal course of
maintenance and repair. All spare parts are carried at the lower of cost (first
in, first out method) or market.
Depreciation -- The Company provides for depreciation of property, plant
and equipment using the straight-line method over estimated useful lives which
range from 7 to 40 years for plant and equipment, and 3 to 7 years for furniture
and fixtures.
Amortization of other assets -- The Company provides for amortization of
other assets using the straight-line method as follows:
Organization, start-up and development costs................ 5 - 30 years
Financing costs............................................. 10 - 15 years
Gas contract costs.......................................... 20 years
Income taxes -- Profits or losses of the Partnership are allocated directly
to the partners for income tax purposes.
ENCO is subject to Canadian income taxes and accounts for income taxes on
the liability method. The liability method recognizes the amount of tax payable
at the date of the consolidated financial statements, as a result of all events
that have been recognized in the consolidated financial statements, as measured
by currently enacted tax laws and rates. Deferred income taxes are provided for
temporary differences in recognition of revenues and expenses for financial and
income tax reporting purposes.
Use of estimates -- The preparation of the consolidated financial
statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the amounts reported in
the consolidated financial statements and accompanying notes. Actual results
could differ from those estimates.
Reclassifications -- Certain 1997 amounts have been reclassified to conform
with the 1998 presentation.
2. PROPERTY, PLANT AND EQUIPMENT
1998 1997
------------ ------------
Land and land improvements...................... $ 381,071 $ 381,071
Plant and equipment............................. 82,828,448 84,888,500
Acquisition of gas properties, including
development thereon........................... 31,421,341 28,691,894
Furniture and fixtures.......................... 303,389 221,394
------------ ------------
114,934,249 114,182,859
Less accumulated depreciation and depletion..... 28,463,193 23,723,005
------------ ------------
Total................................. $ 86,471,056 $ 90,459,854
============ ============
Depreciation expense was $3,163,108 in 1998, $3,184,659 in 1997 and
$3,159,774 in 1996. Depletion expense was $2,137,000 in 1998, $1,861,800 in 1997
and $1,606,000 in 1996.
F-59
96
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
3. OTHER ASSETS
1998 1997
----------- -----------
Organization, start-up and development costs...... $10,170,897 $10,170,897
Financing costs................................. 8,160,723 6,904,723
Gas contract costs.............................. 2,423,060 2,423,060
----------- -----------
20,754,680 19,498,680
Less accumulated amortization..................... 9,899,391 8,679,442
----------- -----------
Total................................... $10,855,289 $10,819,238
=========== ===========
Amortization expense was $1,219,949 in 1998, $1,851,652 in 1997 and
$1,805,748 in 1996.
4. LONG-TERM DEBT
The Partnership and ENCO have four loan agreements with The Prudential
Insurance Company of America (Prudential) and Credit Suisse First Boston (Credit
Suisse), (collectively, the Lenders). On December 31, 1998, the Partnership
entered into its fourth loan agreement with Prudential, the Secured Junior
Subordinated Loan (the Junior Subordinated Loan). The Junior Subordinated Loan
provides up to $40 million for cash distributions, development of gas reserves,
and working capital purposes. At December 31, 1998 and 1997, amounts outstanding
under the loan agreements, by entity, were as follows:
1998 1997
------------ ------------
Sumas Cogeneration Company, L.P.
Term Loan, dated January 30, 1992
10.35% fixed rate portion.................. $ 50,514,104 $ 52,456,954
LIBOR plus 1.0% variable rate portion...... 36,081,500 37,469,250
Subordinated loan, dated September 30, 1997
7.85% fixed rate portion................... 12,000,000 12,000,000
LIBOR plus 1.5% variable rate portion...... 8,000,000 8,000,000
Junior Subordinated Loan, dated December 29,
1998
9.66% fixed rate........................... 14,327,750 --
ENCO Gas, Ltd
Term Loan, dated January 30, 1992
9.99% fixed rate portion................... 13,185,900 13,693,050
LIBOR plus 1.0% variable rate portion...... 9,418,200 9,780,750
------------ ------------
143,527,454 133,400,004
Less current portion....................... 5,400,000 4,200,000
------------ ------------
Total................................. $138,127,454 $129,200,004
============ ============
F-60
97
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Scheduled annual principal payments under the loan agreements as of
December 31, 1998 are as follows:
YEAR ENDING DECEMBER 31, AMOUNT
- ------------------------ ------------
1999........................................... $ 5,400,000
2000........................................... 7,180,000
2001........................................... 12,580,000
2002........................................... 15,000,000
2003........................................... 15,859,664
Thereafter..................................... 87,507,790
------------
Total................................ $143,527,454
============
The Partnership's loans are comprised of fixed and variable interest rate
loans. Fixed rate interest is payable quarterly and variable rate interest is
payable monthly at either the London Interbank Offered Rate (LIBOR), certificate
of deposit rate or Credit Suisse's base rate, plus an applicable margin which
ranges from .5% to 1.75% as stated in the loan agreements. During the year ended
December 31, 1998, variable interest rates ranged from 6.03% to 7.44%. The loans
mature between May 2008 and December, 2010. In addition, the Subordinated Loan
includes a Revolving Line of Credit in the amount of $1,000,000 of which there
were no balances outstanding at December 31, 1998 or 1997.
The Partnership pays Prudential an agency fee of $50,000 per year until the
loans mature. The Partnership pays Credit Suisse an agency fee of $40,000 per
year, adjusted annually by an inflation index, until the loans mature. The loans
are collateralized by substantially all the Company's assets and interests in
the Project. Additionally, the Company's rights under all contractual agreements
are assigned as collateral. The Partnership and ENCO loans are
cross-collateralized and contain cross-default provisions.
Under the terms of the loan agreements and the deposit and disbursement
agreements with the Lenders, the Company is required to establish and fund
certain accounts held by Credit Suisse and Royal Trust as security agents. The
accounts require specified minimum deposits and funding levels to meet current
and future operating, maintenance and capital costs, and to provide certain
other reserves for payment of principal, interest and other contingencies. These
accounts are presented as restricted cash and cash equivalents and include cash,
certificates of deposit, money market accounts and U.S. treasury bills, all with
maturities of 3 months or less. The current portion of restricted cash and cash
equivalents is based on the amount of current liabilities for obligations, which
may be funded from the restricted accounts. The balance of restricted cash and
cash equivalents has been classified as a non-current asset.
5. INCOME TAXES
The provision for income taxes represents Canadian taxes which consist of
the following:
1998 1997 1996
-------- --------- --------
Current
Federal large corporation tax............. $ 42,209 $ 30,708 $ 41,340
British Columbia capital taxes............ 37,571 35,124 34,011
-------- --------- --------
79,780 65,832 75,351
Deferred.................................. 391,430 (591,474) 80,600
-------- --------- --------
$471,210 $(525,642) $155,951
======== ========= ========
F-61
98
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The principal sources of temporary differences resulting in deferred tax
assets and liabilities are as follows:
1998 1997
---------- ----------
Deferred tax asset
Canadian net operating loss carryforwards........... $1,410,438 $1,906,396
Deferred tax liabilities
Acquisition and development costs of gas deducted
for tax purposes in excess of amounts deducted
for financial reporting purposes............... 2,198,794 2,303,322
---------- ----------
Net deferred tax liability................ $ 788,356 $ 396,926
========== ==========
The Company believes, based upon available information, that all deferred
assets will be realized in the normal course of business and no valuation
allowance is necessary.
The provision for income taxes differs from the Canadian statutory rate
principally due to the following:
1998 1997 1996
-------- --------- --------
Canadian statutory rate................... 44.62% 44.62% 44.62%
Income taxes based on statutory rate...... $101,150 $(887,037) $(45,824)
Capital taxes, net of deductible
portion................................. 63,016 49,710 60,175
Non-deductible provincial royalties, net
of resource allowance................... 82,396 216,931 123,464
Depletion on gas properties with no tax
basis................................... 49,843 33,436 36,488
Foreign exchange adjustments.............. 1,021 63,931 16,362
Net capital losses not recognized......... 56,851 -- --
Changes in value of tax losses due to
foreign exchange........................ 100,327 -- --
Other..................................... 16,606 (2,613) (34,714)
-------- --------- --------
$471,210 $(525,642) $155,951
======== ========= ========
As of December 31, 1998, ENCO has non-capital loss carryforwards of
approximately $3,161,000, which may be applied against taxable income of future
periods which expire from 1999 through 2004.
6. RELATED PARTY TRANSACTIONS AND COMMITMENTS
Administrative services -- As managing partner of the Partnership, SEI
receives a fee of $300,000 per year for periods after December 1995. The fee is
subject to annual adjustment based upon an inflation index. Approximately
$334,000 in 1998, $333,000 in 1997 and $311,000 in 1996, was paid to SEI under
this agreement.
Operating and maintenance services -- The Partnership has an operating and
maintenance agreement with a related party to operate, repair and maintain the
Project. For these services, the Partnership pays a fixed fee of $1,140,000 per
year, adjustable based on the Consumer Price Index, an annual base fee of
$150,000 per year, also adjustable based on the Consumer Price Index, and
certain other reimbursable expenses as defined in the agreement. In addition,
the agreement provides for an annual performance bonus of up to $250,000,
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
F-62
99
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
agreements. This agreement expires on the later of the date Whatcom receives
Target Return or the date on which certain loans to affiliates of SEI are
repaid. The agreement contains optional renewal terms. Approximately $2,200,050
in 1998, $2,074,000 in 1997, and $2,014,000 in 1996 was earned under this
agreement.
Thermal energy and kiln lease -- The Partnership has a 20-year thermal
energy and kiln lease agreement with Socco. Under this agreement, Socco leases
the premises and the kiln, and purchases certain amounts of thermal energy
delivered to dry lumber. Income recorded from Socco was approximately $44,000 in
1998, and $9,000 in 1996.
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 $112,000 in 1998, $119,000 in 1997, and $107,000 in
1996 was paid under this agreement.
Fuel supply and purchase agreements -- The Partnership has a fixed price
natural gas sale and purchase agreement with ENCO. The agreement requires ENCO
to deliver up to a maximum daily contract quantity of 24,900 MMBtu's of natural
gas per day. 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 and ENCO have a gas management agreement with Engage Energy
Canada L.P. (Engage). The gas management agreement was assigned to Engage by
Westcoast Gas Services, Inc. during 1997. Engage is paid a gas management fee
for each MMBtu of gas delivered to the Generation Facility. The gas management
fee is adjusted annually, based on the British Columbia Consumer Price Index.
The gas management agreement expires October 31, 2008, unless terminated earlier
as provided for in the agreement.
As collateral for the obligations of the Company under the gas supply and
gas management agreements with Engage, the Partnership has in place an
irrevocable standby letter of credit with Credit Suisse in favor of Engage. As
of December 31, 1998 and 1997, the letter of credit had a face amount of
$500,000.
ENCO is committed to the utilization of gathering, processing and pipeline
capacity on the Westcoast Energy, Inc. (WEI) system. These firm capacity
commitments are under contracts of varying lengths. Firm capacity has been
accepted at an annual cost of approximately $7,187,000 in 1998, $3,553,000 in
1997 and $3,526,000 in 1996.
Future minimum capacity commitments at December 31, 1998 are as follows:
YEAR ENDING DECEMBER 31, AMOUNT
- ------------------------ -----------
1999.......................................... $ 7,057,700
2000.......................................... 3,503,000
2001.......................................... 3,834,200
2002.......................................... 3,710,200
2003.......................................... 2,935,500
Thereafter.................................... 9,644,000
-----------
Total............................... $30,684,600
===========
As collateral for the obligations of ENCO under the capacity contracts with
WEI, the Partnership has in place an irrevocable standby letter of credit with
Credit Suisse in favor of WEI. As of December 31, 1998 and 1997, the letter of
credit had a face amount of approximately $582,000 (Canadian) and $384,000
(Canadian), respectively.
F-63
100
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Utility services -- The Partnership has agreements for utility services
with the City of Sumas, Washington (the City). The City provides water and sewer
services to the Partnership. Water is provided at the City's wholesale rate
charged to external association customers. The City began providing industrial
sewer service to the Partnership in December 1998. Sewer rates are charged at
the City's industrial rate for large users, plus an amount that will repay the
City for sewer improvements made by the City to accommodate the Partnership's
industrial sewage. Both the water supply and sewer services agreements provide
for minimum payments should the Partnership not purchase certain minimum
amounts.
The Partnership maintains a letter of credit in favor of the City to
support its obligations to pay future sewer charges to the City. As of December
31, 1998 and 1997, the letter of credit had a face amount of $625,000 and
$700,000, respectively.
The Partnership also has an agreement for waste water disposal with the
City of Bellingham, Washington. The City of Bellingham has agreed to accept up
to 70,000 gallons of waste water daily at a rate of $0.0115 per gallon. The
agreement expires on December 31, 2003.
The Partnership has a permit for waste water disposal from the Washington
State Department of Ecology which expires June 30, 2000.
Lease commitments -- In December 1990, the Partnership entered into a
23.5-year land lease which may be renewed for five consecutive five-year
periods. Rental expense was approximately $55,600 in 1998, $55,600 in 1997 and
$56,600 in 1996.
In 1997, ENCO signed an operating lease for office space which expires in
March 2001. Monthly rental expense is approximately $1,846. Rental expense was
approximately $21,900 in 1998, $19,000 in 1997 and $20,400 in 1996.
Future minimum land and office lease commitments as of December 31, 1998
are as follows:
YEAR ENDING DECEMBER 31, AMOUNT
- ------------------------ ----------
1999........................................... $ 71,100
2000........................................... 74,300
2001........................................... 61,200
2002........................................... 55,700
2003........................................... 55,700
Thereafter..................................... 750,500
----------
Total................................ $1,068,500
==========
Affiliate loan -- In 1994, the sole shareholder of SEI obtained a loan from
Calpine in the amount of $10,000,000. During 1997, Calpine assigned the loan to
a third party. The sole shareholder of SEI entered into an amended and restated
loan agreement with the new lender.
Affiliate revolving line of credit -- In 1997, the sole shareholder of SEI
entered into a Revolving Loan Agreement with Calpine. The loan agreement
provides for Calpine to loan up to $15,000,000 to the SEI shareholder. Loans
bear interest at a fixed rate of 12.5% and are due in full on December 31, 2003.
As of December 31, 1998 and 1997, no borrowings had been made under the loan.
7. FAIR VALUES OF FINANCIAL INSTRUMENTS
The carrying amount of all cash and cash equivalents, accounts receivable
and accounts payable reported in the consolidated balance sheet is estimated by
the Company to approximate their fair value.
F-64
101
SUMAS CONGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
The Company is not able to estimate the fair value of its debt with a
carrying amount of $143,527,454 and $133,400,004 at December 31, 1998 and 1997,
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.
8. YEAR 2000
The Year 2000 issue is the result of computer programs being written using
two digits rather than four to define the applicable year. Any of the Company's
computer programs or equipment that have date-sensitive software may recognize a
date using "00" as the year 1900 rather than the year 2000. In addition, certain
hardware components may not function properly as the year 2000 approaches. This
could result in a system failure or miscalculations causing disruptions of
operations.
Management is reviewing the Company's computer software programs, hardware
components and other systems, and believes any Year 2000 issues will be resolved
without a material effect on the Company's financial condition and results of
operations.
F-65
102
EXHIBIT INDEX
Exhibit
Number Description
- ------- -----------
27.0 Financial Data Schedule