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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
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(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-12079
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, $.001 PAR VALUE REGISTERED ON THE NEW YORK
STOCK EXCHANGE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE.
Indicate by check mark whether the Registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of the Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates of the
Registrant as of March 13, 2001: $13.1 billion. Common stock outstanding as of
March 13, 2001: 284,794,073.
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 2001 Annual Meeting of
Shareholders.................................. Part III (Items 10, 11, 12 and 13)
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FORM 10-K
ANNUAL REPORT
FOR THE YEAR ENDED DECEMBER 31, 2000
TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 22
Item 3. Legal Proceedings........................................... 24
Item 4. Submission of Matters To A Vote of Security Holders......... 24
PART II
Item 5. Market for Registrant's Common Equity and Related 24
Stockholder Matters.........................................
Item 6. Selected Financial Data..................................... 25
Item 7. Management's Discussion and Analysis of Financial Condition 25
and Results of Operations...................................
Item 7a. Quantitative and Qualitative Disclosure about Market Risk... 25
Item 8. Financial Statements and Supplementary Data................. 25
Item 9. Changes in and Disagreements with Accountants on Accounting 25
and Financial Disclosure....................................
PART III
Item 10. Executive Officers, Directors and Key Employees............. 25
Item 11. Executive Compensation...................................... 25
Item 12. Security Ownership of Certain Beneficial Owners and 26
Management..................................................
Item 13. Certain Relationships and Related Transactions.............. 26
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 26
8-K.........................................................
Signatures.................................................. 32
Index to Consolidated Financial Statements and Other Information....... 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, including
statements regarding the intent, belief or current expectations of Calpine
Corporation ("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 that could
materially affect actual results such as, but not limited to, (i) changes in
government regulations, including pending changes in California, and anticipated
deregulation of the electric energy industry, (ii) commercial operations of new
plants that may be delayed or prevented because of various development and
construction risks, such as a failure to obtain financing and the necessary
permits to operate or the failure of third-party contractors to perform their
contractual obligations, (iii) cost estimates are preliminary and actual costs
may be higher than estimated, (iv) the assurance that the Company will develop
additional plants, (v) a competitor's development of a lower-cost generating
gas-fired power plant, (vi) the risks associated with marketing and selling
power from power plants in the newly competitive energy market, (vii) the risks
associated with marketing and selling combustion turbine parts and components in
the competitive combustion turbine parts market, (viii) the risks associated
with engineering, designing and manufacturing combustion turbine parts and
components, (ix) delivery and performance risks associated with combustion
turbine parts and components attributable to production, quality control,
suppliers and transportation, (x) the successful exploitation of an oil or gas
resource that ultimately depends upon the geology of the resource, the total
amount and cost to develop recoverable reserves, and operational factors
relating to the extraction of natural gas, or (xi) those risks and uncertainties
identified in Management's Discussion and Analysis -- Risk Factors included with
the Consolidated Financial Statements in this report and incorporated into this
Item 1 -- Business section. Prospective investors are also cautioned that the
California energy market remains uncertain. The Company's management is working
closely with a number of parties to resolve the current uncertainty. This is an
ongoing process and, therefore, the outcome cannot be predicted. It is possible
that any such outcome will include changes in government regulations, business
and contractual relationships or other factors that could materially affect the
Company. However, management believes that a final resolution will not have a
material adverse impact on the Company. Prospective investors are also referred
to the 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 50 power plants having a net capacity of 5,849
megawatts. We also have 25 gas-fired projects under construction having a net
capacity of 14,028 megawatts and have announced plans to develop 28 gas-fired
projects (power plants and expansions of current facilities) with a net capacity
of 15,142 megawatts. Upon completion of the projects under construction, we will
have interests in 74 power plants located in 21 states having a net capacity of
19,877 megawatts. Of this total generating capacity, 96% will be attributable to
gas-fired facilities and 4% 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
1996 2000 GROWTH RATE
--------- --------- ---------------
(DOLLARS IN MILLIONS)
Total Revenue.................................. $ 214.6 $2,282.8 81%
EBITDA......................................... 110.7 825.9 65%
Net Income..................................... 18.7 323.5 104%
Total Assets................................... 1,031.4 9,737.3 75%
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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, power
marketing 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.
THE MARKET
The power industry represents the third largest industry in the United
States, with an estimated end-user market of over $215 billion of electricity
sales in 2000 produced by an aggregate base of power generation facilities with
a capacity of approximately 860,000 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 business 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 growth strategy, we
utilize our management and technical knowledge 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 production,
acquisition, operations and power marketing, which we believe provides us with a
competitive advantage. The key elements of our strategy are as follows:
- Development of new and expansion of existing power plants. We are
actively pursuing the development of new, and expansion of both baseload
and peaking capacity at our existing, highly efficient, low-cost,
gas-fired power plants to replace old and inefficient generating
facilities and meet the demand for new generation.
- 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 the
opportunity to enhance the operating efficiencies of the plants.
- Enhancement of existing power plants. We continually seek to maximize the
power generation and revenue potential of our operating assets and
minimize our operating and maintenance expenses and fuel costs.
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RECENT DEVELOPMENTS
Project Development and Construction. On February 12, 2001, we announced
that the Florida Public Service Commission approved a joint application filed by
Calpine and Seminole Electric Cooperative, Inc. ("Seminole"), under which we
will build the Osprey Energy Center to supply electric power to help meet
Seminole's members' power needs.
Issuance of Securities. On February 15, 2001, we completed a public
offering of $1.15 billion of our 8 1/2% Senior Notes due 2011. The Senior Notes
due 2011 bear interest at 8 1/2% per year, payable semi-annually, and mature on
February 15, 2011.
California Power Market. The deregulation of the California power market
has produced significant unanticipated results in the past year. The
deregulation froze the rates that utilities can charge their retail and business
customers in California and prohibited the utilities from buying power on a
forward basis, while wholesale power prices were not subjected to limits.
In the past year, a series of factors have reduced the supply of power to
California, which has resulted in wholesale power prices that have been
significantly higher than historical levels. Several factors contributed to this
increase. These included:
- significantly increased volatility in prices and supplies of natural gas;
- an unusually dry fall and winter in the Pacific Northwest, which reduced
the amount of available hydroelectric power from that region (typically,
California imports a portion of its power from this source);
- the large number of power generating facilities in California nearing the
end of their useful lives, resulting in increased downtime (either for
repairs or because they have exhausted their air pollution credits and
replacement credits have become too costly to acquire on the secondary
market); and
- continued obstacles to new power plant construction in California, which
deprived the market of new power sources that could have, in part,
ameliorated the adverse effects of the foregoing factors.
As a result of this situation, two major California utilities that are
subject to the retail rate freeze, including Pacific Gas & Electric Company
("PG&E"), have faced wholesale prices that far exceed the retail prices they are
permitted to charge. This has led to significant underrecovery of costs by these
utilities; and they have been widely reported to be facing the prospect of
insolvency. As a consequence, these utilities have defaulted under a variety of
contractual obligations, including payment obligations to power generators. PG&E
has defaulted on payment obligations to us. (For additional information,
including information on certain receivables, see Notes 15 and 19 of the Notes
to Consolidated Financial Statements.)
We have historically sold power to PG&E, which is one of the California
utilities that is subject to the rate freeze. We are currently selling power to
PG&E pursuant to long-term qualifying facility ("QF") contracts, which are
subject to federal regulation under the Public Utility Regulatory Policies Act
of 1978, as amended ("PURPA") (16 U.S.C. sec. 796 et seq.). The QF contracts
provide that the California Public Utilities Commission ("CPUC") has the
authority to determine the appropriate utility "avoided cost" to be used to set
energy payments for certain QF contracts, including those for all of our QF
plants in California which sell power to PG&E. Section 390 of the California
Public Utility Code provided QFs the option to elect to receive energy payments
based on the California Power Exchange ("PX") market clearing price. In mid-
2000, our QF facilities elected this option and were paid based upon the PX
zonal day ahead clearing price ("PX Price") from summer 2000 until January 19,
2001, when the PX ceased operating a day ahead market. Since that time, the CPUC
has ordered that the price to be paid for energy deliveries by QFs electing the
PX Price shall be based on a natural gas cost-based "transition formula." The
CPUC has conducted proceedings (R. 99-11-022) to determine whether the PX Price
was the appropriate price for the energy component upon which to base payments
to QFs which had elected the PX based pricing option. It is possible that the
CPUC could order a payment adjustment based on a different energy price
determination. We believe that the PX Price was the appropriate price for energy
payments but there can be no assurance that this will be the outcome of the CPUC
proceedings. Legislation has recently been introduced in the California
legislature
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(SB 47X) that would establish a fixed price for the QF contracts for a 5 year
period and would eliminate any PX Price adjustment prior to December 31, 2000.
There can be no assurances that this legislation will be enacted.
We have continued to honor our contractual obligations to PG&E under our QF
contracts. To date, we have refrained from pursuing our collection remedies with
respect to PG&E's default, however, we have been actively involved with the
California utilities, the California legislature, and other interested parties
to develop legislation designed to stabilize energy prices through the
application of a long-term energy pricing methodology (for a five-year period)
in place of the short-term pricing methodology currently utilized under the QF
contracts, as discussed above. We also expect further legislation to enable the
California utilities to finance over a longer term the difference between the
wholesale prices that have been paid and the retail prices they received during
last fall and into this winter. We believe that this should enhance PG&E's
ability to make payment of all past due amounts. However, management cannot
predict the timing or ultimate outcome of the legislative process or the payment
of amounts due under our contracts.
As this situation has deteriorated, California has taken steps to restore a
predictable and reliable power market to the State. Recently, California adopted
legislation permitting it to issue long-term revenue bonds to provide funding
for wholesale purchases of power. The bonds will be repaid with the proceeds of
payments by retail customers over time. The California Department of Water
Resources ("DWR") sought bids for long-term power supply contracts. We
successfully bid in that auction, and announced, as indicated below, that we
have signed three significant long-term power supply contracts with DWR.
On February 7, 2001, we announced the signing of a 10-year, $4.6 billion
fixed-price contract with DWR to provide electricity to the State of California.
We committed to sell up to 1,000 megawatts of electricity, with initial
deliveries of 200 megawatts starting October 1, 2001, and increasing to 1,000
megawatts by January 1, 2004. This contract will continue through 2011. The
electricity will be sold directly to DWR on a 24-hour, 7-day-a-week basis.
On February 28, 2001, we announced the signing of two long-term power sales
contracts with DWR. Under the terms of the first contract, a $5.2 billion,
10-year, fixed-price contract, we commit to sell up to 1,000 megawatts of
generation. Initial deliveries are scheduled to begin July 1, 2001 with 200
megawatts and increase to 1,000 megawatts by as early as July 2002. Under the
terms of the second contract, a 20-year contract totaling up to $3.1 billion, we
will supply DWR with up to 495 megawatts of peaking generation, beginning with
90 megawatts as early as August 2001, and increasing up to 495 megawatts as
early as August 2002.
On March 13, 2001, we announced the signing of a two-month deal to provide
555 megawatts of electricity to DWR from our new South Point Energy Center
during plant testing, effective immediately through May 15, 2001.
FERC Investigation into California Wholesale Markets. Beginning in May 2000,
wholesale energy prices in the California markets increased to levels well above
1999 levels. In response, on June 28, 2000, the ISO Board of Governors reduced
the price cap applicable to the ISO's wholesale energy and ancillary services
markets from $750/MWh to $500/MWh. The ISO subsequently reduced the price cap to
$250/MWh on August 1, 2000. During this period, however, the California Power
Exchange Corporation ("PX") maintained a separate price cap set at a much higher
level applicable to the "day-ahead" and "day-of" markets administered by the PX.
On August 23, 2000, the FERC denied a complaint filed August 2, 2000 by San
Diego Gas & Electric Company ("SDG&E") that sought to extend the ISO's $250
price cap to all California energy and ancillary service markets, not just the
markets administered by the ISO. However, in its order denying the relief sought
by SDG&E, the FERC instructed its staff to initiate an investigation of the
California power markets and to report its findings to the FERC and held further
hearing procedures in abeyance pending the outcome of this investigation.
On November 1, 2000, the FERC released a Staff Report detailing the results
of the Staff investigation, together with an "Order Proposing Remedies for
California Wholesale Markets" ("November 1 Order"). In the November 1 Order, the
FERC found that the California power market structure and market rules were
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seriously flawed, and that these flaws, together with short supply relative to
demand, resulted in unusually high energy prices. The November 1 Order proposed
specific remedies to the identified market flaws, including: (a) imposition of a
so-called "soft" price cap at $150/MWh to be applied to both the PX and ISO
markets, which would allow bids above $150/MWh to be accepted, but will subject
such bids to certain reporting obligations requiring sellers to provide cost
data and/or identify applicable opportunity costs and specifying that such bids
may not set the overall market clearing price, (b) elimination of the
requirement that the California utilities sell into and buy from the PX, (c)
establishment of independent non-stakeholder governing boards for the ISO and
the PX, and (d) establishment of penalty charges for scheduling deviations
outside of a prescribed range. In the November 1 Order the FERC established
October 2, 2000, the date 60 days after the filing of the SDG&E complaint, as
the "refund effective date." Under the November 1 Order, rates charged for
service after that date through December 31, 2002 will remain subject to refund
if determined by the FERC not to be just and reasonable. While the FERC
concluded that the Federal Power Act and prior court decisions interpreting that
act strongly suggested that refunds would not be permissible for charges in the
period prior to October 2, 2000, it noted that it was willing to explore
proposals for equitable relief with respect to charges made in that period. All
of the Company's receivables from PG&E relate to energy generated by QF
facilities. Under FERC regulations, QF contracts are exempt from regulation
under the Federal Power Act, which is the legislation that provides the
authority for the FERC to compel refunds or frame other equitable relief with
respect to the California wholesale markets. See "Government
Regulation -- Federal Energy Regulation -- Federal Power Act Regulation."
Therefore, the Company believes that any refund or other equitable remedy that
the FERC may impose with respect to the California wholesale markets will not
affect the Company's ability to pursue payment by PG&E of all past due amounts
as described above.
On December 15, 2000, the FERC issued a subsequent order that affirmed in
large measure the November 1 Order (the "December 15 Order"). Various parties
have filed requests for administrative rehearing and for judicial review of
aspects of the FERC's December 15 Order. The outcome of these proceedings, and
the extent to which the FERC or a reviewing court may revise aspects of the
December 15 Order or the extent to which these proceedings may result in a
refund of or reduction in the amounts charged by the Company's subsidiaries for
power sold in the ISO and PX markets, cannot be determined at this time.
DESCRIPTION OF FACILITIES
At March 8, 2001, Calpine had interests in 50 power generation facilities
representing 5,849 megawatts of net capacity. Of these 50 projects, 31 are
gas-fired power plants with a net capacity of 4,999 megawatts, and 19 are
geothermal power generation facilities with a net capacity of 850 megawatts. We
also have 24 gas-fired projects and one project expansion currently under
construction with a net capacity of 14,028 megawatts, and have announced the
development of 21 additional power plants and seven project expansions with a
net capacity of 15,142 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 our projects under construction, we will provide
operating and maintenance services for 69 of the 74 power plants in which we
have an interest. Such services include the operation of power plants,
geothermal steam fields, wells and well pumps, gas fields, gathering systems and
gas pipelines. We also supervise maintenance, materials purchasing and inventory
control, manage cash flow, train staff and prepare
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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 reliability or profitability.
These services are sometimes 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 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. See "Properties"
for further discussion of our gas reserves.
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 project financing that is structured to be serviced out
of the cash flows derived from the sale of electricity and thermal energy
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 we own or are leased on a long-term basis.
See "Properties."
Set forth below is certain information regarding our operating power
plants, plants under construction, and announced development projects.
MEGAWATTS
--------------------------------------------------
CALPINE NET CALPINE NET
NUMBER BASELOAD PEAKING INTEREST INTEREST
OF PLANTS CAPACITY CAPACITY BASELOAD PEAKING
--------- -------- -------- ----------- -----------
In operation
Geothermal power plants.............. 19 850 850 850 850
Gas-fired power plants............... 31 4,866 5,916 4,007 4,999
Under construction
New facilities....................... 24 13,418 15,446 11,807 13,668
Expansion projects (one)............. -- -- 360 -- 360
Announced development
New facilities....................... 21 12,253 14,514 11,987 14,225
Expansion projects (seven)........... -- 322 917 322 917
-- ------ ------ ------ ------
95 31,709 38,003 28,973 35,019
== ====== ====== ====== ======
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OPERATING POWER PLANTS
CALPINE NET CALPINE NET
BASELOAD PEAKING CALPINE INTEREST INTEREST 2000
STATE OR CAPACITY CAPACITY INTEREST BASELOAD PEAKING GENERATION
POWER PLANT PROVINCE (MW) (MW) PERCENTAGE (MW) (MW) MWH
----------- -------- -------- -------- ---------- ----------- ----------- ----------
GEOTHERMAL POWER PLANTS
Sonoma County (12 plants)...... CA 512.0 512.0 100.0% 512.0 512.0 3,488,792
Lake County (2 plants)......... CA 145.0 145.0 100.0% 145.0 145.0 944,441
Calistoga...................... CA 73.0 73.0 100.0% 73.0 73.0 533,531
Sonoma......................... CA 53.0 53.0 100.0% 53.0 53.0 380,478
West Ford Flat................. CA 27.0 27.0 100.0% 27.0 27.0 217,231
Bear Canyon.................... CA 20.0 20.0 100.0% 20.0 20.0 146,193
Aidlin......................... CA 20.0 20.0 100.0% 20.0 20.0 149,074
------- ------- ------- ------- ----------
Total Geothermal
Power Plants....... 850.0 850.0 850.0 850.0 5,859,740
======= ======= ======= ======= ==========
GAS-FIRED POWER PLANTS
Pasadena Power Plant........... TX 751.0 787.0 100.0% 751.0 787.0 3,150,018
Broad River Energy Center...... SC -- 541.0 100.0% -- 541.0 21,451
Hidalgo Energy Center.......... TX 502.0 502.0 78.5% 394.1 394.1 981,498
Texas City Power Plant......... TX 465.0 471.0 100.0% 465.0 471.0 3,413,022
Clear Lake Power Plant......... TX 335.0 412.0 100.0% 335.0 412.0 2,937,853
Rumford Power Plant............ ME 237.0 251.0 100.0% 237.0 251.0 105,256
Tiverton Power Plant........... RI 240.0 240.0 100.0% 240.0 240.0 292,798
Gordonsville Power Plant....... VA 233.0 238.0 50.0% 116.5 119.0 119,287
Lockport Power Plant........... NY 177.0 198.0 11.4% 20.1 22.5 186,826
DePere Energy Center........... WI -- 180.0 100.0% -- 180.0 53,631
Morris Power Plant............. IL 155.0 177.5 86.0% 134.0 146.4 535,323
Bayonne Power Plant............ NJ 158.0 170.0 7.5% 11.9 12.8 105,277
Dighton Power Plant............ MA 162.0 168.0 100.0% 162.0 168.0 839,746
Androscoggin Energy Center..... ME 160.0 160.0 32.3% 51.7 51.7 53,979
Auburndale Power Plant......... FL 143.0 153.0 100.0% 143.0 153.0 512,118
Grays Ferry Power Plant........ PA 143.0 148.0 40.0% 57.2 59.2 417,485
Gilroy Power Plant............. CA 112.0 131.0 100.0% 112.0 131.0 917,348
Pryor Power Plant.............. OK 109.0 124.0 80.0% 87.2 99.2 321,146
Sumas Power Plant.............. WA 120.0 122.0 50.0% 60.0 61.0 1,087,658
Parlin Power Plant............. NJ 89.0 118.0 80.0% 71.2 94.4 347,002
King City Power Plant.......... CA 103.0 115.0 100.0% 103.0 115.0 914,807
Kennedy International Airport
Power Plant("KIAC").......... NY 95.0 105.0 100.0% 95.0 105.0 231,404
Pittsburg Power Plant.......... CA 64.0 71.0 100.0% 64.0 71.0 438,444
Newark Power Plant............. NJ 47.0 58.0 80.0% 37.6 46.4 271,164
Bethpage Power Plant........... NY 52.0 53.7 100.0% 52.0 53.7 384,448
Greenleaf 1 Power Plant........ CA 50.0 50.0 100.0% 50.0 50.0 379,205
Greenleaf 2 Power Plant........ CA 50.0 50.0 100.0% 50.0 50.0 358,961
Stony Brook Power Plant........ NY 36.0 40.0 100.0% 36.0 40.0 125,455
Watsonville Power Plant........ CA 29.0 30.0 100.0% 29.0 30.0 219,516
Agnews Power Plant............. CA 26.5 28.6 100.0% 26.5 28.6 113,798
Philadelphia Water Project..... PA 22.0 23.0 66.4% 14.6 15.3 890
------- ------- ------- ------- ----------
Total Gas-Fired Power
Plants............. 4,865.5 5,915.8 4,006.6 4,999.3 19,836,814
======= ======= ======= ======= ==========
Total Operating Power
Plants............. 5,715.5 6,765.8 4,856.6 5,849.3 25,696,554
======= ======= ======= ======= ==========
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PROJECTS UNDER CONSTRUCTION AND ANNOUNCED DEVELOPMENT
CALPINE NET CALPINE NET
POWER BASELOAD PEAKING CALPINE INTEREST INTEREST
GENERATION STATE OR CAPACITY CAPACITY INTEREST BASELOAD PEAKING
POWER PLANT TECHNOLOGY PROVINCE (MW) (MW) PERCENTAGE (MW) (MW)
----------- ---------- -------- -------- -------- ---------- ----------- -----------
PROJECTS UNDER CONSTRUCTION
Acadia Energy Center.............. Gas LA 1,080.0 1,239.0 50.0% 540.0 619.5
Oneta Energy Center............... Gas OK 960.3 1,137.8 100.0% 960.3 1,137.8
Freestone Energy Center........... Gas TX 1,002.8 1,051.6 100.0% 1,002.8 1,051.6
Delta Energy Center............... Gas CA 798.0 874.0 50.0% 399.0 437.0
Baytown Power Plant............... Gas TX 704.0 834.0 100.0% 704.0 834.0
Decatur Energy Center............. Gas AL 659.0 794.0 100.0% 659.0 794.0
Morgan Energy Center.............. Gas AL 660.0 790.0 100.0% 660.0 790.0
Magic Valley Generating Station... Gas TX 687.0 750.0 100.0% 687.0 750.0
Hermiston Power Project........... Gas OR 530.0 630.0 100.0% 530.0 630.0
Channel Energy Center............. Gas TX 519.0 628.0 100.0% 519.0 628.0
Aries Power Plant................. Gas MO 516.0 591.0 50.0% 258.0 295.5
Washington Parish Energy Center... Gas LA 490.0 577.0 100.0% 490.0 577.0
South Point Energy Center......... Gas AZ 526.0 555.0 100.0% 526.0 555.0
Los Medanos Energy Center......... Gas CA 493.0 555.0 100.0% 493.0 555.0
Sutter Power Plant................ Gas CA 516.0 547.0 100.0% 516.0 547.0
Lost Pines 1 Power Plant.......... Gas TX 522.0 545.0 50.0% 261.0 272.5
Ontelaunee Energy Center.......... Gas PA 511.0 541.0 100.0% 511.0 541.0
Westbrook Energy Center........... Gas ME 487.0 525.0 100.0% 487.0 525.0
RockGen Energy Center............. Gas WI -- 523.8 100.0% -- 523.8
Corpus Christi Energy Center...... Gas TX 522.7 522.7 100.0% 522.7 522.7
Carville Energy Center............ Gas LA 522.7 522.7 100.0% 522.7 522.7
Broad River Energy Center
Expansion....................... Gas SC -- 360.0 100.0% -- 360.0
Santa Rosa Energy Center.......... Gas FL 252.0 252.0 100.0% 252.0 252.0
Hog Bayou Energy Center........... Gas AL 246.6 246.6 66.7% 164.5 164.5
Pine Bluff Energy Center.......... Gas AR 213.3 213.3 66.7% 142.3 142.3
-------- -------- -------- --------
Total Projects Under
Construction.......... 13,418.4 15,805.5 11,807.3 14,027.9
======== ======== ======== ========
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CALPINE NET CALPINE NET
POWER BASELOAD PEAKING CALPINE INTEREST INTEREST
GENERATION STATE OR CAPACITY CAPACITY INTEREST BASELOAD PEAKING
POWER PLANT TECHNOLOGY PROVINCE (MW) (MW) PERCENTAGE (MW) (MW)
----------- ---------- -------- -------- -------- ---------- ----------- -----------
ANNOUNCED DEVELOPMENT
Blue Heron Energy Center.......... Gas FL 1,080.0 1,239.0 100.0% 1,080.0 1,239.0
Lawrence Energy Center............ Gas OH 850.0 1,100.0 100.0% 850.0 1,100.0
East Altamont Energy Center....... Gas CA 820.0 1,065.0 100.0% 820.0 1,065.0
Haywood Energy Center............. Gas TN 800.0 915.0 100.0% 800.0 915.0
Lone Oak Energy Center............ Gas MS 800.0 915.0 100.0% 800.0 915.0
Augusta Energy Center............. Gas GA 750.0 850.0 100.0% 750.0 850.0
Hillabee Energy Center............ Gas AL 710.0 770.0 100.0% 710.0 770.0
Fremont Energy Center............. Gas OH 550.0 700.0 100.0% 550.0 700.0
Wawayanda Energy Center........... Gas NY 530.0 630.0 100.0% 530.0 630.0
Otay Mesa Generating Project...... Gas CA 540.0 618.0 100.0% 540.0 618.0
Teayawa Energy Center............. Gas CA 530.0 608.0 100.0% 530.0 608.0
RiverGen Energy Center............ Gas WI 450.0 600.0 100.0% 450.0 600.0
Osprey Energy Center.............. Gas FL 530.0 590.0 100.0% 530.0 590.0
Metcalf Energy Center............. Gas CA 532.5 578.7 50.0% 266.3 289.4
Thompson Creek Energy Center...... Gas LA 500.0 575.0 100.0% 500.0 575.0
Columbia Energy Center............ Gas SC 500.0 550.0 100.0% 500.0 550.0
Hammond Energy Center............. Gas IN 500.0 550.0 100.0% 500.0 550.0
Mt. Vernon Energy Center.......... Gas IN 522.7 522.7 100.0% 522.7 522.7
Towantic Energy Center............ Gas CT 508.0 508.0 100.0% 508.0 508.0
California Peakers (4 projects)... Gas CA -- 495.0 100.0% -- 495.0
Zion Energy Center................ Gas IL -- 330.0 100.0% -- 330.0
Calgary Energy Centre............. Gas AB 250.0 300.0 100.0% 250.0 300.0
Pine Bluff Energy Center
Expansion....................... Gas AR 246.6 246.6 100.0% 246.6 246.6
Auburndale Expansion.............. Gas FL -- 100.0 100.0% -- 100.0
DePere Energy Center Expansion.... Gas WI 75.0 75.0 100.0% 75.0 75.0
-------- -------- -------- --------
Total Announced
Development........... 12,574.8 15,431.0 12,308.6 15,141.7
======== ======== ======== ========
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, power
marketing, 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
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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.
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
to provide competitively priced and environmentally friendly power to
electricity markets. 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.
Projects Under Construction
Acadia Energy Center. On March 6, 2000, we announced that we entered into a
partnership agreement with Cleco Midstream Resources, an affiliate of Pineville,
Louisiana-based Cleco Corporation, to participate in the Acadia Energy Center.
The partners plan to build, own and operate the 1,239 megawatt natural gas-
fired energy center near Eunice, Louisiana. We have a 620 megawatt net interest
in this facility. Construction began in mid 2000 and commercial operation for
the energy center is expected in May 2002. On October 20, 2000, we jointly
announced with Cleco Corporation the signing of a 20-year contract with Aquila
Energy, a wholly owned subsidiary of UtiliCorp United, for 580 megawatts of the
output of the jointly owned Acadia Energy Center. Under terms of a tolling
agreement, starting July 1, 2002, Aquila Energy will supply the natural gas
needed to generate 580 megawatts of electricity and will own and market the
produced power.
Oneta Energy Center. On July 20, 2000, we completed the acquisition of the
development rights to construct, own and operate the Oneta Energy Center from
Panda Energy, International, Inc. Oneta is a 1,138 megawatt natural gas-fired
energy center under construction in Coweta, Oklahoma, southeast of Tulsa. We
anticipate that the Oneta Energy Center will commence commercial operation in
July 2002.
Freestone Energy Center. On June 15, 2000, we announced that we acquired
the rights to develop, build, own and operate the Freestone Energy Center from
New Orleans, Louisiana-based Entergy Corp. Freestone is a 1,052 megawatt natural
gas-fired energy center located in Freestone County, Texas, near Fairfield,
about 80 miles southeast of Dallas. Construction commenced in August 2000 and
commercial operation is expected to begin in the summer of 2002.
Delta Energy Center. In February 1999, we, together with Bechtel
Enterprises, announced plans to develop an 874 megawatt gas-fired cogeneration
energy center in Pittsburg, California in which we have a 437 megawatt net
interest. 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. Construction began in April 2000 and we expect
commercial operation to commence in May 2002.
Baytown Power Plant. In October 1999, we announced plans to build, own and
operate an 834 megawatt gas-fired cogeneration power plant at Bayer
Corporation's chemical facility in Baytown, Texas. The Baytown Power Plant will
supply Bayer with all of its electric and steam requirements for 20 years and
market excess electricity into the Texas wholesale power market. Construction
commenced in early 2000 and commercial operation is expected to commence in late
2001.
Decatur Energy Center. On February 2, 2000, we announced plans to build,
own and operate a 794 megawatt gas-fired cogeneration energy center at Solutia
Inc.'s Decatur, Alabama chemical facility. Under a 20-year agreement, Solutia
will lease a portion of the facility to meet its electricity needs and
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purchase its steam requirements from us. Excess power from the facility will be
sold into the Southeastern Wholesale Power Market under a variety of short,
medium and long-term contracts. We will also build a new intrastate natural gas
pipeline to fuel the energy center. Construction began in September 2000 and
commercial operation is expected to commence in mid 2002.
Morgan Energy Center. On June 27, 2000, we announced plans to build, own
and operate a natural gas-fired cogeneration energy center at the BP Amoco
chemical facility in Decatur, Alabama. The proposed Morgan Energy Center will
generate approximately 790 megawatts of electricity in addition to supplying
steam for BP Amoco's facility. Construction began in September 2000 and we
expect commercial operation to commence in December 2002.
Magic Valley Generating Station. In May 1998, we announced that we 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 750 megawatt natural
gas-fired generating station under construction in Edinburg, Texas. Magic Valley
Electric Cooperative Inc., 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. Construction commenced in
the spring of 1999 with commercial operation scheduled to begin in the second
quarter of 2001.
Hermiston Power Project. On January 28, 2000, we acquired the development
rights for the Hermiston Power Project, a 630 megawatt gas-fired cogeneration
power facility located near Hermiston, Oregon. Construction commenced in the
summer of 2000 and we anticipate that commercial operation of the facility will
commence in mid 2002.
Channel Energy Center. In October 1999, we announced we had executed a
letter of intent that gave us the exclusive right to negotiate with
LYONDELL-CITGO Refining LP to build, own and operate a 628 megawatt gas-fired
cogeneration energy center at the LYONDELL-CITGO refinery in Houston, Texas. The
Channel Energy Center will supply all of the electricity and steam requirements
for 20 years to the refinery. Construction began in early 2000 and commercial
operation is expected to begin in the summer of 2001.
Aries Power Plant. On January 14, 2000, we acquired a 296 megawatt net
interest in the Aries Power Plant, a 591 megawatt natural gas-fired plant
currently under construction near Pleasant Hill, Missouri, from a subsidiary of
Aquila Energy Corporation. Construction started in the fall of 1999 and
commercial operation is scheduled to begin in late 2001. The majority of the
facility's output will be sold to Missouri Public Service through May 2005.
Thereafter, power will be sold into the Southwest Power Pool and the Southeast
Electric Reliability Counsel regional power markets.
Washington Parish Energy Center. On January 26, 2001, we announced the
acquisition of the development rights from Cogentrix, an independent power
company based in North Carolina, for the 577 megawatt Washington Parish Energy
Center, located near Bogalusa, Louisiana. We are managing construction of the
facility, which began in January 2001, and will operate the facility when it
enters commercial operation in 2002.
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 555
megawatt gas-fired power plant on the tribe's reservation in Mojave County,
Arizona. Construction commenced in August 1999 and we anticipate that the South
Point Power Plant will begin operation in May 2001. In accordance with a
five-year power sales agreement with the Imperial Irrigation District ("IID"),
we will deliver 150 megawatts of electricity from the South Point Power Plant to
IID's southern California electric customers beginning in May 2002. Thereafter,
the electricity generated will be sold to the Arizona, Nevada and California
power markets.
Los Medanos Energy Center. In September 1999, we finalized an agreement
with Enron North America for the development rights of a 555 megawatt gas-fired
energy center in Pittsburg, California. We expect that the Los Medanos Energy
Center will be California's second newly constructed power facility since
deregulation of the California power market in 1998. Construction commenced in
September 1999 and
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commercial operation is expected to begin in the summer of 2001. The facility
will provide electricity and industrial steam totaling approximately 65
megawatts to USS-POSCO Industries under a long-term agreement. The remaining
output will be sold into the California power market.
Sutter Power Plant. In February 1997, we announced plans to develop a 547
megawatt gas-fired combined cycle power plant in Sutter County, in northern
California. The Sutter Power Plant is expected to be California's first newly
constructed power plant since deregulation of the California power market in
1998. Construction commenced in the third quarter of 1999 and the Sutter Power
Plant is expected to begin commercial operation in the summer of 2001. In
accordance with an agreement we entered into with the Sacramento Municipal
Utility District ("SMUD") on January 18, 2000, the Sutter Power Plant will
provide 150 megawatts of electricity to SMUD's customer base for a five-year
period beginning with the plant's startup.
Lost Pines 1 Power Plant. In September 1999, we entered into definitive
agreements with Austin, Texas-based GenTex Power Corporation, the power
generation affiliate of the Lower Colorado River Authority, to build a 545
megawatt gas-fired power plant in Bastrop County, Texas. We have a 273 megawatt
net interest in this facility. Construction began in October 1999 and commercial
operation is expected to begin in mid 2001. Upon commercial operation, GenTex
will take half of the electrical output for sale to its customers, and we will
market the remaining energy to the Texas power market.
Ontelaunee Energy Center. In June 1999, we announced that we had acquired
the rights to develop a 541 megawatt gas-fired energy center in Ontelaunee
Township in eastern Pennsylvania. Construction began in July 2000 and commercial
operation is estimated to commence in the spring of 2002. Output from the
Ontelaunee Energy Center will be sold into the Pennsylvania/New Jersey/Maryland
("PJM") power pool and pursuant to bilateral contracts.
Westbrook Energy Center. In February 1999, we acquired from Genesis Power
Corporation, a New England based power developer, the development rights to a
525 megawatt gas-fired combined cycle energy center located in Westbrook, Maine.
Construction commenced in early 1999 and commercial operation is scheduled for
the spring of 2001. It is anticipated that the output generated by the Westbrook
Energy Center will be sold into the New England power market and to wholesale
and retail customers in the northeastern United States.
RockGen Energy Center. The 524 megawatt RockGen Energy Center is located in
the town of Christiana in Dane County, Wisconsin. Construction began in April
2000 and we expect commercial operation to commence in July 2001. On August 10,
1998, IES Utilities, Wisconsin Power and Light Company and Interstate Power
Company (collectively the "Alliant Utilities") entered into a long-term power
purchase agreement with the RockGen Energy Center. In January 1999, the RockGen
Energy Center also entered into a long-term tolling arrangement with Duke Energy
Trading and Marketing, L.L.C.
Corpus Christi Energy Center. The Corpus Christi Energy Center is a 523
megawatt combined cycle, cogeneration energy center located in Corpus Christi,
Texas. Construction began in June 2000 and we expect commercial operation to
begin in June 2002. In March 1999, a long-term energy services agreement was
executed with CITGO Refining and Chemicals Company, L.P. ("CITGO") under which
CITGO will purchase from the Corpus Christi Energy Center all of the steam and
electricity that it requires but does not internally generate at its Corpus
Christi refinery.
Carville Energy Center. The Carville Energy Center is a 523 megawatt
combined cycle, cogeneration energy center located in St. Gabriel, Louisiana.
Construction of the facility began in October 2000 and commercial operation is
expected to commence in May 2002. On December 28, 1999, a long-term energy
services agreement was executed with Cos-Mar Inc. ("Cos-Mar") under which
Cos-Mar will purchase from the Carville Energy Center all of the steam and
electric power (if allowed under applicable regulations) that it requires but
does not internally generate at its St. Gabriel chemical plant.
Broad River Energy Center Expansion. This expansion, the second phase of
construction of the Broad River Energy Center, involves the installation of two
additional combustion turbines capable of producing an additional 360 megawatts
of peaking power. Construction is expected to be completed in the spring of
2001.
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On November 15, 2000, we announced that our wholly owned subsidiary, SkyGen
Energy LLC ("SkyGen"), entered into an agreement to supply CP&L Energy ("CP&L")
additional power produced from the Broad River Energy Center Expansion project.
Santa Rosa Energy Center. The Santa Rosa Energy Center is a 252 megawatt
combined cycle, energy center located near Pensacola, Florida. Construction
began in September 2000 and commercial operation is expected to commence in
September 2002.
Hog Bayou Energy Center. We have a 165 megawatt net interest in this 247
megawatt gas-fired combined cycle facility located in Mobile, Alabama.
Construction of the facility began in July 1999 and commercial operation is
expected to commence in June 2001.
Pine Bluff Energy Center. We have a 142 megawatt interest in this 213
megawatt steam and electric power cogeneration energy center near Pine Bluff,
Arkansas. Construction began in September 1999 and we anticipate the facility
will commence commercial operation in May 2001. On November 25, 1998,
International Paper entered into a long-term energy services agreement under
which International Paper will purchase from the Pine Bluff Energy Center all of
the steam and electric power (if allowed under applicable regulations) that it
requires but does not internally generate at its Pine Bluff mill.
Announced Development Projects
Blue Heron Energy Center. On January 11, 2000 we announced plans to build,
own and operate a 1,239 megawatt gas-fired cogeneration energy center in Indian
River County, Florida outside of Vero Beach. We anticipate that construction
will commence in early 2002 and that commercial operation of the facility will
commence in mid 2004.
Lawrence Energy Center. On October 23, 2000, we announced that we entered
into a project development agreement to build, own and operate a 1,100 megawatt
natural gas-fired energy center to be located on the Ohio River in Hamilton
Township in Lawrence County, Ohio. The proposed Lawrence Energy Center will
represent a $510 million investment, with a target commercial operation date of
December 2004.
East Altamont Energy Center. On December 12, 2000, we announced that we are
considering plans to develop and operate a new energy-efficient electric
generating facility, the proposed $550 million East Altamont Energy Center,
located in the northeastern corner of Alameda County in northern California. We
are preparing technical studies for the proposed 1,065 megawatt facility. Upon
completion of licensing through the California Energy Commission ("CEC"),
construction would begin in June 2002, with commercial operation beginning in
June 2004.
Haywood Energy Center. On July 19, 2000, we announced we will develop,
construct and own a natural gas-fired, combined cycle power generation facility
in Haywood County, Tennessee. The 915 megawatt facility is scheduled to begin
commercial operation in late 2004.
Lone Oak Energy Center. On February 22, 2000, we announced plans to build,
own and operate the Lone Oak Energy Center, a 915 megawatt gas-fired
cogeneration facility in Lowndes County, Mississippi. We anticipate that
construction will commence in mid 2001 and that commercial operation of the
facility will commence in the spring of 2003.
Augusta Energy Center. On January 17, 2001, our wholly owned subsidiary,
SkyGen, announced plans to build, own and operate an 850 megawatt natural
gas-fired cogeneration energy center in Augusta, Georgia. The proposed Augusta
Energy Center will supply energy to DSM Chemicals North America, Inc. for use in
its production processes. Construction is expected to begin in the third quarter
of 2001, with an estimated commercial operation date of May 2003.
Hillabee Energy Center. On February 24, 2000, we announced plans to build,
own and operate the Hillabee Energy Center, a 770 megawatt gas-fired
cogeneration facility in Tallapoosa County, Alabama. We anticipate that
construction will commence in mid 2001 and that commercial operation of the
facility will commence in mid 2003.
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Fremont Energy Center. On May 23, 2000, we announced the acquisition of
development rights to build, own and operate a 700 megawatt gas-fired facility
to be located near Fremont, Ohio. Construction is scheduled to begin in mid 2001
and we expect commercial operation to commence in mid 2003.
Wawayanda Energy Center. On March 23, 2000, we announced plans to build,
own and operate the Wawayanda Energy Center, a 630 megawatt gas-fired facility
to be located near Middletown, New York. We anticipate that construction will
begin in early 2002 and commercial operation will begin in early 2004.
Otay Mesa Generating Project. On December 18, 2000, we announced with PG&E
Corporation an agreement under which we will acquire the rights to construct the
Otay Mesa Generating Project in San Diego County. In accordance with the terms
of the agreement, we will build, own and operate the 618 megawatt generating
facility, and PG&E Corporation's National Energy Group will contract for up to
250 megawatts of the project's output. Construction is expected to begin in the
fall of 2001 and commercial operation is scheduled for the fall of 2003.
Teayawa Energy Center. On June 29, 2000, we announced that we secured the
rights to develop, build, own and operate the Teayawa Energy Center, a 608
megawatt natural gas-fired power generating facility near the town of Thermal in
Riverside County, California through a development agreement with Adair
International Oil and Gas, Inc. The Teayawa Energy Center will be sited on the
Torres Martinez Desert Cahuilla Indians' land through a long-term lease
agreement with the Torres Martinez. Construction is scheduled to begin in early
2002 and commercial operation is expected in early 2004.
RiverGen Energy Center. Our proposed 600 megawatt RiverGen Energy Center
will be located near Beloit, Wisconsin. Construction of the RiverGen Energy
Center is expected to begin during the fourth quarter of 2001, with commercial
operation starting in late 2003. On February 13, 2001, we announced that our
wholly owned subsidiary, SkyGen Energy LLC, entered into a ten-year agreement to
supply Wisconsin Power & Light Company 453 megawatts of electric capacity and
energy from the proposed RiverGen Energy Center.
Osprey Energy Center. On January 11, 2000, we announced plans to build, own
and operate the Osprey Energy Center, a 590 megawatt gas-fired cogeneration
energy center near the city of Auburndale, Florida. On February 12, 2001, the
Florida Public Service Commission approved the application for the facility,
which will be built adjacent to our existing power facility, the Auburndale
Power Plant. We anticipate that construction will commence in the fall of 2001
and commercial operation of the facility will commence in the fall of 2003. In
accordance with an agreement we entered into with Tampa, Florida-based Seminole,
the Osprey Energy Center will supply electric power to help meet Seminole's
member systems' power needs for a period of 17 years beginning in June 2003.
Metcalf Energy Center. In February 1999, we, together with Bechtel
Enterprises, announced plans to develop, own and operate a 579 megawatt
gas-fired cogeneration energy center in San Jose, California. We have a 289
megawatt net interest in this facility. The CEC is currently considering whether
to override a November 2000 vote by the San Jose City Council denying a request
to change the zoning designation of the land at the proposed site. We cannot
predict at this time whether the CEC will in fact override this vote. If the CEC
does elect to override this vote, we expect the CEC review, licensing and public
hearing process would be completed in mid 2001. We would then anticipate that
construction would commence, subject to any further delays, and that commercial
operation of the facility would commence in late 2003. We plan to sell the
electricity generated by the Metcalf Energy Center into the California power
market.
Thompson Creek Energy Center. The Thompson Creek Energy Center is a 575
megawatt combined cycle, cogeneration project located in Louisiana. We expect
construction to begin in late 2001 and anticipate that the facility will
commence commercial operation in late 2003.
Columbia Energy Center. The Columbia Energy Center is a 550 megawatt
combined cycle cogeneration project located in Columbia, South Carolina. We
expect construction will commence in June 2001 and commercial operation will
begin in May 2003. On August 15, 2000, a long-term energy services agreement was
executed with Eastman Chemical Company ("Eastman") under which Eastman will
purchase from the Columbia Energy Center all of the steam and electric power (if
allowed under applicable regulations) that it requires but does not internally
generate at its Columbia chemical plant.
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Hammond Energy Center. The Hammond Energy Center is a 550 megawatt facility
to be located in Indiana. Construction is scheduled to begin in late 2001 and
commercial operation is expected in late 2003.
Mt. Vernon Energy Center. The Mt. Vernon Energy Center is a 523 megawatt
facility to be located in Indiana. Construction is scheduled to begin in late
2001 and commercial operation is expected to commence in late 2003.
Towantic Energy Center. In November 1999, we completed the acquisition of
development rights to build, own and operate the Towantic Energy Center. The
Towantic Energy Center is a 508 megawatt gas-fired cogeneration plant located in
Oxford, Connecticut. This power plant will market its electricity via bilateral
contracts into the New England region. In February 2000, a town-wide referendum
in the Town of Oxford, Connecticut approved the sale of the town-owned land for
the Towantic Energy Center. Construction is estimated to commence in mid 2002
and commercial operation is expected in March 2004.
California Peakers (4 projects). Eleven GE LM6000 turbines will be
installed at four of our operating gas-fired power plants in California to
increase peaking capacity by a total of 495 megawatts. Six turbines will be
installed at the Gilroy Power Plant, three at the Watsonville Power Plant, one
at the Greenleaf 2 Power Plant and one at the King City Power Plant.
Zion Energy Center. The Zion Energy Center is a 330 megawatt simple cycle
facility located in Zion, Illinois. Construction is scheduled to begin in July
2001 with commercial operation expected to commence in April 2002. In December
2000, a contract was executed for the long-term sale of capacity from the Zion
Energy Center.
Calgary Energy Centre. On April 20, 2000, we announced plans to construct
the Calgary Energy Centre. Scheduled to begin commercial operation in early
2003, the 300 megawatt combined cycle, natural gas-fired facility was the first
independent power project announced in the Calgary area, and represents our
first investment in the Canadian power industry.
Pine Bluff Energy Center Expansion. Construction on this 247 megawatt
expansion of the Pine Bluff Energy Center is expected to commence in September
2001 and operation is anticipated to begin in September 2003.
Auburndale Expansion. On July 6, 2000, we announced the addition of 100
megawatts of peaking capacity to the natural gas-fired, cogeneration facility
located in Auburndale, Florida. Construction is scheduled to begin in October
2001 with commercial operation expected to commence in early 2002.
DePere Energy Center Expansion. This second phase of construction of the
DePere Energy Center will convert the DePere, Wisconsin facility from a 180
megawatt simple cycle gas-fired combustion turbine to a 255 megawatt combined
cycle cogeneration system. The expansion is expected to be complete by January
2004. All electric capacity and energy will be sold to the Wisconsin Public
Service Corporation under a 25-year power purchase agreement. Nicolet Paper
Company, an affiliate of International Paper Company, will purchase the
cogenerated steam.
OIL AND GAS PROPERTIES
Montis Niger. In January 1997, we purchased Montis Niger, Inc., a gas
production and pipeline company operating primarily in the Sacramento Basin in
northern California, which we subsequently renamed Calpine Gas Company. As of
December 31, 2000, Calpine Gas Company owned proven natural gas reserves,
leasehold acreage and operated an 80-mile pipeline delivering gas to our
Greenleaf 1 and 2 Power Plants. We currently supply the majority of the fuel
requirements for the Greenleaf 1 and 2 Power Plants.
Calpine Natural Gas Company. In October 1999, we purchased Sheridan Energy,
Inc., a natural gas exploration and production company operating in northern
California and the Gulf Coast region, which we subsequently renamed Calpine
Natural Gas Company ("CNGC"). CNGC's oil and gas properties are primarily
natural gas and are located in strategic markets where we are developing
low-cost natural gas supplies and proprietary pipeline systems in support of our
natural gas-fired power plants.
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Vintage. In December 1999, we completed the acquisition of Vintage
Petroleum, Inc.'s ("Vintage") interest in the Rio Vista Gas Unit and related
areas, representing primarily natural gas reserves located in the Sacramento
Basin in northern California. As a result of this acquisition and the Sheridan
Energy, Inc. ("Sheridan") acquisition, we own a 99.5% working interest in the
Rio Vista Gas Unit and certain development acreage in northern California.
Western. On February 4, 2000, we acquired 100% of the stock of Western Gas
Resources California ("Western") from Western Gas Resources, Inc. Western's
assets include the 130-mile Steelhead natural gas pipeline and the remaining
interest in the Sacramento River Gas System natural gas pipeline, now 100% owned
by us.
Gulf of Mexico. In June 2000, we acquired an interest in the East Cameron,
High Island and South Pelto fields in the Gulf of Mexico which includes 10
producing wells and 5 drilling locations enhanced with 3-D seismic, one of which
has already been successfully drilled.
Calpine Canada Natural Gas, Ltd. On July 5, 2000, we purchased
Calgary-based Quintana Minerals Canada Corp. ("QMCC"), a natural gas exploration
and production company, whose reserves are located in British Columbia, Alberta
and Saskatchewan provinces in Canada. We subsequently changed its name to
Calpine Canada Natural Gas, Ltd. ("CCNG"). The assets include interests in 1,300
wells.
Additionally, in November 2000, we acquired TriGas Exploration Inc.
("TriGas"), of Calgary, Alberta, an exploration company focused on developing
and producing gas reserves in south-central Alberta. We subsequently merged the
company into CCNG. The assets include an interest in 74 producing wells located
in the Acme, Lone Pine, Lone Pine South and Irricana fields, 48,000 net acres of
undeveloped lands, two compression facilities, a 26.6% working interest in the
Crossfield gas processing plant located near the fields, and a majority interest
in 63 miles of pipeline that conduct the gas to two nearby gas-fired power
generation facilities.
Colorado and Gulf Coast. In July 2000, we acquired natural gas assets in
the Piceance Basin, Colorado and onshore Gulf Coast from a privately-held
Houston, Texas-based company. The assets include 126 producing wells, 79,000
acres of undeveloped lands, and 195 potential drilling locations with historical
success rates of over 90 percent.
Encal Energy Ltd. ("Encal"). On February 8, 2001, we announced our plans to
acquire all of the common shares of Encal, a Calgary, Alberta-based natural gas
and petroleum exploration and development company, through a stock-for-stock
exchange in which Encal shareholders will receive Cdn. $12.00 per share in
Calpine common equivalent shares based on an exchange ratio to be determined
prior to closing. The aggregate value of the transaction, for which we expect to
use pooling of interests accounting, is approximately $1.2 billion, including
the assumed indebtedness of Encal. Upon completion of the acquisition, we will
gain approximately 1.0 trillion cubic feet equivalent of proved and provable
natural gas resources, net of royalties. This transaction also provides access
to firm gas transportation capacity from western Canada to California and the
eastern U.S., and an accomplished management team capable of leading our
business expansion in Canada. With the addition of Encal's assets, which
currently produce approximately 230 million cubic feet of gas equivalent
("mmcfe") per day, net of royalties, our net production is expected to increase
to 390 mmcfe per day in North America, enough to fuel approximately 2,300
megawatts of our power fleet. We expect to close this transaction during the
second quarter of 2001.
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 our 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 sell at retail electricity that they have purchased from
independent producers. Under certain circumstances where specific
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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 PURPA and the adoption of regulations thereunder by
the Federal Energy Regulatory Commission ("FERC") provided incentives for the
development of cogeneration facilities and small power production facilities
(those utilizing renewable fuels and having a capacity of less than 80
megawatts).
A domestic electricity generating project must be a QF under FERC
regulations in order to take advantage of certain rate and regulatory incentives
provided by PURPA. PURPA exempts owners of QFs from the Public Utility Holding
Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions
of the Federal Power Act (the "FPA") and, except under certain limited
circumstances, state laws concerning rate or financial regulation. These
exemptions are important to us and our competitors. We believe that each of the
electricity generating projects in which we own an interest and which operates
as a QF power producer 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 and state 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 QF or other
qualifying small power producer) must not be controlled or more than 50% owned
by one or more electric utilities or by most electric utility holding companies,
or one or more subsidiaries 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.
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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 also trigger certain rights of termination under
the facility's power sales agreement, could subject the facility to rate
regulation as a public utility under the FPA and state law and could result in
us inadvertently becoming an electric 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 electric 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 facility can be qualified as an
exempt wholesale generator ("EWG"), meaning that all of its output is sold for
resale rather than to end users, 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 would be required. In
addition, the facility would be required to cease selling electricity to any
retail customers (such as the thermal energy customer) to retain its EWG status
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 apply only to new projects, and 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 Securities and Exchange Commission
("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-QF electric generating
facilities 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 these amendments benefit us by expanding
our ability to own and operate facilities that do not qualify for QF status.
However, they have also resulted in increased competition by allowing utilities
and their affiliates to develop such facilities which are not subject to the
constraints of PUHCA.
Federal Natural Gas Transportation Regulation
We have an ownership interest in 55 gas-fired cogeneration plants in
operation or under construction. The cost of natural gas is ordinarily the
largest expense of a gas-fired 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, whether firm or non-firm
transportation is purchased and the operations of the gas pipeline); and
obligations to take a minimum quantity of gas and pay for it (i.e., take-and-pay
obligations).
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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, interstate pipeline rates and terms and conditions for such
services are subject to continuing FERC oversight.
Federal Power Act Regulation
Under the FPA, FERC is authorized to regulate the transmission of electric
energy and the sale of electric energy at wholesale in interstate commerce.
Unless otherwise exempt, any person that owns or operates facilities used for
such purposes is considered a "public utility" subject to FERC jurisdiction.
FERC regulation under the FPA includes approval of the disposition of utility
property, authorization of the issuance of securities by public utilities,
regulation of the rates, terms and conditions for the transmission or sale of
electric energy at wholesale in interstate commerce, the regulation of
interlocking directorates, a uniform system of accounts and reporting
requirements for public utilities.
FERC regulations implementing PURPA provide that a QF is exempt from
regulation under the foregoing provisions of the FPA. An EWG is not exempt from
the FPA and therefore an EWG that makes sales of electric energy at wholesale in
interstate commerce is subject to FERC regulation as a "public utility."
However, many of the regulations which customarily apply to traditional public
utilities have been waived or relaxed for power marketers, EWGs and other
non-traditional public utilities that lack market power. EWGs are regularly
granted authorization to charge market based rates, blanket authority to issue
securities, and waivers of certain FERC requirements pertaining to accounts,
reports and interlocking directorates. Such action is intended to implement
FERC's policy to foster a more competitive wholesale power market.
Many of the generating projects in which we own an interest are operated as
QFs and are therefore exempt from FERC regulation under the FPA. However,
several of our generating projects are or will be EWGs subject to FERC
jurisdiction under the FPA. Several of our affiliates have been granted
authority to engage in sales at market based rates and to issue securities and
have also been granted the customary waivers of FERC regulations available to
non-traditional public utilities; however we cannot assure that such authorities
or waivers will be granted in the future to other affiliates.
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 operating in their states 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, such as EWGs, 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 a power purchase agreement with an
independent power producer to the utility's retail customers. However, a
regulatory commission under certain circumstances may disallow the full
reimbursement to a utility for the cost to purchase power from a QF or an EWG.
In addition, retail sales of electricity or thermal energy by an independent
power producer may be subject to PUC regulation depending on state law.
Independent power producers which are not QFs under PURPA, or EWGs pursuant to
the Energy Policy Act of 1992, are considered to be public utilities in many
states and are subject to broad regulation by a PUC, ranging from requirement of
certificate of public convenience and necessity to regulation of organizational,
accounting, financial and other corporate matters. States may assert
jurisdiction over the siting and construction of electric generating facilities
including QFs and EWGs and, with the exception of QFs, over the issuance of
securities and the sale or other transfer of assets by these facilities.
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
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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 natural gas
and the construction and operation of wellfields, pipelines and 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 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.
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 of 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
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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 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 send
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.
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RISK FACTORS
SEE "RISK FACTORS" SECTION STARTING ON PAGE F-23 UNDER "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"
INCLUDED IN APPENDIX F TO THIS REPORT.
EMPLOYEES
As of December 31, 2000, we employed 1,883 people, of whom 33 were
represented by collective bargaining agreements. We have never experienced a
work stoppage or strike, and we consider relations with our employees to be
good.
ITEM 2. PROPERTIES
Our principal executive office located in San Jose, California is held
under leases that expire through 2011, and we also lease regional offices in
Pleasanton, California; Houston, Texas; Boston, Massachusetts and Northbrook,
Illinois. We hold additional leases for our Construction Management office in
Folsom, California, our Turbine Maintenance Group office in LaPorte, Texas, our
Plant Optimization Group office in Fort Collins, Colorado, our c*Power office in
Pleasanton, California, our Project Development office in Tampa, Florida, our
Government Affairs office in Washington, D.C. and our Natural Gas Operations
offices in Houston, TX, Denver, Colorado and Calgary, Alberta.
We have leasehold interests in 105 leases comprising 21,217 acres of
federal, state and private geothermal resource lands in The Geysers area in
northern California. 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 these 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 have complied with all the requirements and conditions material to the
continued effectiveness of the leases. 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.
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Based on independent petroleum engineering reports of Netherland, Sewell &
Associates, Inc., McDaniel & Associates Consultants, Ltd. and Gilbert Laustsen
Jung Associates, Ltd., as of December 31, 2000, utilizing year end product
prices and costs held constant, our proved oil and natural gas reserve volumes,
in thousands of barrels ("MBbls") and billion cubic feet ("Bcf") and associated
future net reserves, undiscounted and discounted at 10% ("PV 10") before future
income taxes, are as follows:
AS OF DECEMBER 31, 2000
---------------------------------------------------------
OIL (MBBLS) GAS (BCF) UNDISCOUNTED PV 10
----------- --------- -------------- --------------
(IN THOUSANDS) (IN THOUSANDS)
UNITED STATES
Proved developed....................... 2,568 268 $2,760,126 $1,387,418
Proved undeveloped..................... 971 65 580,099 303,961
----- --- ---------- ----------
Total........................ 3,539 333 $3,340,225 $1,691,379
===== === ========== ==========
CANADA
Proved developed....................... 3,612 102 $1,070,526 $ 665,951
Proved undeveloped..................... 311 16 178,096 95,059
----- --- ---------- ----------
Total........................ 3,923 118 $1,248,622 $ 761,010
===== === ========== ==========
Proved oil and natural gas reserves are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Estimated
future development costs associated with proved non-producing and proved
undeveloped reserves for 2000 total approximately $69.2 million.
The following table sets forth our interest in undeveloped acreage,
developed acreage and productive wells in which we own a working interest as of
December 31, 2000. Productive wells are wells in which we have a working
interest and are capable of producing oil or natural gas. Gross represents the
total number of acres or wells in which we own a working interest. Net
represents our proportionate working interest resulting from our ownership in
the gross acres or wells.
UNDEVELOPED ACRES DEVELOPED ACRES PRODUCTIVE WELLS
------------------ ------------------ -----------------
GROSS NET GROSS NET GROSS NET
------- ------- ------- ------- ------- -----
UNITED STATES
Arkansas........................... -- -- 8,823 3,967 35 15
California......................... 30,143 23,755 77,308 73,261 155 130
Colorado........................... 24,078 18,813 28,721 16,803 39 39
Louisiana.......................... 42,558 41,542 28,323 27,860 37 13
Mississippi........................ 350 277 10,125 4,584 16 4
Montana............................ 9,890 7,458 1,280 640 2 1
Oklahoma........................... 4,765 953 29,878 13,938 88 20
Texas.............................. 17,481 7,123 21,587 9,815 134 49
Wyoming............................ 47,936 35,584 -- -- -- --
Offshore Louisiana................. 6,250 6,250 8,750 8,750 5 5
Offshore Texas..................... -- -- 5,760 3,142 10 5
------- ------- ------- ------- ----- ---
Total.................... 183,451 141,755 220,555 162,760 521 281
======= ======= ======= ======= ===== ===
CANADA............................. 385,725 225,577 492,055 205,768 2,268 311
We own the Texas City, Clear Lake and Pasadena Power Plants, which lease an
aggregate of 48 acres. We own 40 gross acres and 38 net acres in Edinburg, Texas
where we are constructing the Magic Valley Power Plant. We own 77 acres in
Sutter County, California, on which the Greenleaf 1 Power Plant is located. We
own 78 acres in Dane County, Wisconsin, on which the RockGen Energy Center is
being constructed. We own 49 acres in Zion, Illinois, on which the Zion Energy
Center will be constructed. We own 40 acres in
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Iberville Parish, Louisiana, on which the Carville Energy Center is being
constructed. See "Description of Facilities" for a description of the other
leased or owned properties in which we have an interest. We believe that our
properties are adequate for our current operations.
ITEM 3. LEGAL PROCEEDINGS
An action was filed against Lockport Energy Associates, L.P. 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 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. On September 29, 2000,
the New York Federal District Court dismissed NYSEG's complaint and NYPSC's
cross-claim. The Court stated that FERC has no authority to alter or waive its
regulations or exemptions to alter the terms of the applicable power purchase
agreements and that Qualifying Facilities are entitled to the benefit of their
bargain, even if at the expense of NYSEG and its ratepayers. NYSEG has filed an
appeal with respect to this decision. In any event, the Company retains the
right to require The Brooklyn Union Gas Company to purchase its interest in the
Lockport Power Plant for $18.9 million, less equity distributions received by
us, 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Retirement Savings Plan. Effective September 1999, Calpine Corporation
amended its Retirement Savings Plan to add a Calpine Common Stock Fund as one of
the investment options for employee contributions to the Plan. As the result of
this amendment, the exemption from registration under the Securities Act of 1933
for both the plan participation interests and the shares of Common Stock
previously afforded by Section 3(a)(2) of the Securities Act ceased to be
available. In April 2000, Calpine filed with the Securities and Exchange
Commission a registration statement on Form S-8 registering both the plan
participation interest and shares of Common Stock for future issuance under the
Plan. While Calpine believes that many of the sales made prior to such
registration would qualify as exempt transactions under Section 4(2) of the
Securities Act, it has not undertaken an evaluation of the eligibility of each
Plan participant to purchase securities in a private placement, and expects that
such an evaluation would show that not all of the Plan participants who
purchased unregistered securities would qualify.
Since the plan amendment, through December 2000, Calpine estimates that (i)
as of December 31, 2000, the market value of the plan participation interests
sold was $53,550,819 and (ii) Calpine has sold to participants 1,402,221 shares
of Common Stock, in each case without the registration of the securities under
the Securities Act. Because employee contributions that are directed to the
Calpine Common Stock Fund are used by the Plan's trustee to purchase shares of
Common Stock in the open market, Calpine does not receive any proceeds from the
sale of the shares. Calpine is prepared to rescind any sale of plan
participation interests or common stock made prior to the registration of such
plan participation interests and common stock if requested by a participant who
did not qualify for a private placement.
SkyGen Acquisition. On October 12, 2000, in connection with the acquisition
of SkyGen, the Company privately placed 2,117,742 shares of its Common Stock
with the stockholders of SkyGen as part of the purchase price paid by the
Company for SkyGen. The private placement was made in reliance on
24
27
Regulation D under the Securities Act of 1933 on the basis that each of such
stockholders was an "accredited investor" within the meaning of Rule 501(a)
under the Securities Act of 1933.
PSM Acquisition. On December 13, 2000, in connection with the acquisition
of PSM, the Company privately placed 281,189 shares of its Common Stock with the
members of PSM as part of the purchase price paid by the Company for PSM,
including such member's membership interests in PSM. The private placement was
made in reliance on Regulation D under the Securities Act of 1933 on the basis
that each of such members was an "accredited investor" within the meaning of
Rule 501(a) under the Securities Act of 1933, with the exception of one such
member who was otherwise qualified under Regulation D.
EMI Acquisition. On December 15, 2000, in connection with the acquisition
of EMI, the Company privately placed 1,102,601 shares of its Common Stock with
the limited partners of EMI as part of the purchase price paid by the Company
for EMI, including such limited partners' interests in the Tiverton, Rumford or
Dighton subsidiaries of EMI. The private placement was made in reliance on
Regulation D under the Securities Act of 1933 on the basis that each of such
limited partners was an "accredited investor" within the meaning of Rule 501(a)
under the Securities Act of 1933.
ITEM 6. SELECTED FINANCIAL DATA
The information required hereunder is set forth under "Selected
Consolidated Financial Data" included in the Consolidated Financial Statements
that are a part of 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 the Consolidated Financial Statements that are a part of this
report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The information required hereunder is set forth under "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Financial Market Risks" included in the Consolidated Financial
Statements that are a part of 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 Stockholders' Equity,"
"Consolidated Statements of Cash Flows," and "Notes to Consolidated Financial
Statements" included in the Consolidated Financial Statements that are a part of
this report. Other financial information and schedules are included in the
Consolidated Financial Statements that are a part of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES
Incorporated by reference to Proxy Statement relating to the 2001 Annual
Meeting of Shareholders to be filed.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference to Proxy Statement relating to the 2001 Annual
Meeting of Shareholders to be filed.
25
28
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference to Proxy Statement relating to the 2001 Annual
Meeting of Shareholders to be filed.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated by reference to Proxy Statement relating to the 2001 Annual
Meeting of Shareholders to be filed.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)-1. FINANCIAL STATEMENTS AND OTHER INFORMATION
The following items appear in Appendix F of this report:
Selected Consolidated Financial Data
Management's Discussion and Analysis of Financial Condition and Results
of Operations
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 2000 and 1999
Consolidated Statements of Operations for the Years Ended December 31,
2000, 1999 and 1998
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2000, 1999 and 1998
Consolidated Statements of Cash Flows for the Years Ended December 31,
2000, 1999 and 1998
Notes to Consolidated Financial Statements for the Years Ended December
31, 2000, 1999 and 1998
(a)-2. FINANCIAL STATEMENT SCHEDULES
Schedule II -- Valuation and Qualifying Accounts
(b) REPORTS ON FORM 8-K
The registrant filed the following report on Form 8-K during the quarter
ended December 31, 2000:
DATE OF REPORT DATE FILED ITEM REPORTED
-------------- ---------- -------------
October 26, 2000 October 27, 2000 5, 7
(c) EXHIBITS
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.1.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(*)
3.1.2 Certificate of Correction of Calpine Corporation.(*)
3.1.3 Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation.(*)
3.1.4 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation.(*)
3.2 Amended and Restated Bylaws of Calpine Corporation, a
Delaware corporation.(d)
4.1.1 Indenture dated as of February 17, 1994 between the Company
and State Street Bank and Trust Company (successor trustee
to Shawmut Bank of Connecticut, National Association), as
Trustee, including form of Notes.(a)
4.1.2 First Supplemental Indenture dated as of July 31, 2000
between the Company and State Street Bank and Trust Company
(successor trustee to Shawmut Bank Connecticut, National
Association), as Trustee.(*)
26
29
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.2.1 Indenture dated as of May 16, 1996 between the Company and
Fleet National Bank, as Trustee, including form of Notes.(c)
4.2.2 First Supplemental Indenture dated as of August 1, 2000
between the Company and State Street Bank and Trust Company
(successor trustee to Fleet National Bank), as Trustee.(*)
4.3.1 Indenture dated as of July 8, 1997 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(e)
4.3.2 Supplemental Indenture dated as of September 10, 1997
between the Company and The Bank of New York, as Trustee.(q)
4.3.3 Second Supplemental Indenture dated as of July 31, 2000
between the Company and The Bank of New York, as Trustee.(*)
4.4.1 Indenture dated as of March 31, 1998 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(g)
4.4.2 Supplemental Indenture dated as of July 24, 1998 between the
Company and The Bank of New York, as Trustee.(g)
4.4.3 Second Supplemental Indenture dated as of July 31, 2000
between the Company and The Bank of New York, as Trustee.(*)
4.5.1 Indenture dated as of March 29, 1999 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(h)
4.5.2 First Supplemental Indenture dated as of July 31, 2000
between the Company and The Bank of New York, as Trustee.(*)
4.6.1 Indenture dated as of March 29, 1999 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(h)
4.6.2 First Supplemental Indenture dated as of July 31, 2000
between the Company and The Bank of New York, as Trustee.(*)
4.7.1 Indenture dated as of August 10, 2000 between the Company
and Wilmington Trust Company, as Trustee.(m)
4.7.2 First Supplemental Indenture dated as of September 28, 2000
between the Company and Wilmington Trust Company, as
Trustee.(*)
4.8 Rights Agreement, dated as of June 5, 1997, between Calpine
Corporation and First Chicago Trust Company of New York, as
Rights Agent.(l)
4.9 HIGH TIDES I.
4.9.1 Certificate of Trust of Calpine Capital Trust, a Delaware
statutory trust, filed October 4, 1999.(i)
4.9.2 Corrected Certificate of Certificate of Trust of Calpine
Capital Trust, a Delaware statutory trust, dated September
29, 1999.(i)
4.9.3 Declaration of Trust of Calpine Capital Trust, dated as of
October 4, 1999, among Calpine Corporation, as Depositor,
The Bank of New York (Delaware), as Delaware Trustee, The
Bank of New York, as Property Trustee, and the
Administrative Trustees named therein.(i)
4.9.4 Indenture, dated as of November 2, 1999, between Calpine
Corporation and The Bank of New York, as Trustee, including
form of Debenture.(i)
4.9.5 Remarketing Agreement, dated November 2, 1999, among Calpine
Corporation, Calpine Capital Trust, The Bank of New York, as
Tender Agent, and Credit Suisse First Boston Corporation, as
Remarketing Agent.(i)
27
30
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.9.6 Amended and Restated Declaration of Trust of Calpine Capital
Trust, dated as of November 2, 1999, among Calpine
Corporation, as Depositor and Debenture Issuer, The Bank of
New York (Delaware), as Delaware Trustee, and The Bank of
New York, as Property Trustee, and the Administrative
Trustees named therein, including form of Preferred Security
and form of Common Security.(i)
4.9.7 Preferred Securities Guarantee Agreement, dated as of
November 2, 1999, between Calpine Corporation and The Bank
of New York, as Guarantee Trustee.(i)
4.10 HIGH TIDES II.
4.10.1 Certificate of Trust of Calpine Capital Trust II, a Delaware
statutory trust, filed January 25, 2000.(n)
4.10.2 Declaration of Trust of Calpine Capital Trust II, dated as
of January 24, 2000, among Calpine Corporation, as Depositor
and Debenture Issuer, The Bank of New York (Delaware), as
Delaware Trustee, The Bank of New York, as Property Trustee,
and the Administrative Trustees named therein.(n)
4.10.3 Indenture, dated as of January 31, 2000, between Calpine
Corporation and The Bank of New York, as Trustee, including
form of Debenture.(n)
4.10.4 Remarketing Agreement, dated as of January 31, 2000, among
Calpine Corporation, Calpine Capital Trust II, The Bank of
New York, as Tender Agent, and Credit Suisse First Boston
Corporation, as Remarketing Agent.(n)
4.10.5 Registration Rights Agreement, dated January 31, 2000, among
Calpine Corporation, Calpine Capital Trust II, Credit Suisse
First Boston Corporation and ING Barings LLC.(n)
4.10.6 Amended and Restated Declaration of Trust of Calpine Capital
Trust II, dated as of January 31, 2000, among Calpine
Corporation, as Depositor and Debenture Issuer, The Bank of
New York (Delaware), as Delaware Trustee, The Bank of New
York, as Property Trustee, and the Administrative Trustees
named therein, including form of Preferred Security and form
of Common Security.(n)
4.10.7 Preferred Securities Guarantee Agreement, dated as of
January 31, 2000, between Calpine Corporation and The Bank
of New York, as Guarantee Trustee.(n)
4.11 HIGH TIDES III.
4.11.1 Amended and Restated Certificate of Trust of Calpine Capital
Trust III, a Delaware statutory trust, filed July 19,
2000.(o)
4.11.2 Declaration of Trust of Calpine Capital Trust III dated June
28, 2000, among the Company, as Depositor and Debenture
Issuer, The Bank of New York (Delaware), as Delaware
Trustee, The Bank of New York, as Property Trustee and the
Administrative Trustees named therein.(o)
4.11.3 Amendment No. 1 to the Declaration of Trust of Calpine
Capital Trust III dated July 19, 2000, among the Company, as
Depositor and Debenture Issuer, Wilmington Trust Company, as
Delaware Trustee, Wilmington Trust Company, as Property
Trustee, and the Administrative Trustees named therein.(o)
4.11.4 Indenture dated as of August 9, 2000, between the Company
and Wilmington Trust Company, as Trustee.(o)
4.11.5 Remarketing Agreement dated as of August 9, 2000, among the
Company, Calpine Capital Trust III, Wilmington Trust
Company, as Tender Agent, and Credit Suisse First Boston
Corporation, as Remarketing Agent.(o)
4.11.6 Registration Rights Agreement dated as August 9, 2000,
between the Company, Calpine Capital Trust III, Credit
Suisse First Boston Corporation, ING Barings LLC and CIBC
World Markets Corp.(o)
28
31
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.11.7 Amended and Restated Declaration of Trust of Calpine Capital
Trust III dated as of August 9, 2000, the Company, as
Depositor and Debenture Issuer, Wilmington Trust Company, as
Delaware Trustee, Wilmington Trust Company, as Property
Trustee, and the Administrative Trustees named therein,
including the form of Preferred Security and form of Common
Security.(o)
4.11.8 Preferred Securities Guarantee Agreement dated as of August
9, 2000, between the Company, as Guarantor, and Wilmington
Trust Company, as Guarantee Trustee.(o)
4.12 PASS THROUGH CERTIFICATES.
4.12.1 Pass Through Trust Agreement dated as of December 19, 2000,
among Tiverton Power Associates Limited Partnership, Rumford
Power Associates Limited Partnership and State Street Bank
and Trust Company of Connecticut, National Association, as
Pass Through Trustee, including the form of Certificate.(*)
4.12.2 Participation Agreement dated as of December 19, 2000, among
the Company, Tiverton Power Associates Limited Partnership,
Rumford Power Associates Limited Partnership, PMCC Calpine
New England Investment LLC, PMCC Calpine NEIM LLC, State
Street Bank and Trust Company of Connecticut, National
Association, as Indenture Trustee, and State Street Bank and
Trust Company of Connecticut, National Association, as Pass
Through Trustee.(*)
4.12.3 Appendix A -- Definitions and Rules of Interpretation.(*)
4.12.4 Indenture of Trust, Mortgage and Security Agreement, dated
as of December 19, 2000, between PMCC Calpine New England
Investment LLC and State Street Bank and Trust Company of
Connecticut, National Association, as Indenture Trustee,
including the forms of Lessor Notes.(*)
4.12.5 Calpine Guaranty and Payment Agreement (Tiverton) dated as
of December 19, 2000, by Calpine, as Guarantor, to PMCC
Calpine New England Investment LLC, PMCC Calpine NEIM LLC,
State Street Bank and Trust Company of Connecticut, as
Indenture Trustee, and State Street Bank and Trust Company
of Connecticut, as Pass Through Trustee.(*)
4.12.6 Calpine Guaranty and Payment Agreement (Rumford) dated as of
December 19, 2000, by Calpine, as Guarantor, to PMCC Calpine
New England Investment LLC, PMCC Calpine NEIM LLC, State
Street Bank and Trust Company of Connecticut, as Indenture
Trustee, and State Street Bank and Trust Company of
Connecticut, as Pass Through Trustee.(*)
10.1 Purchase Agreements.
10.1.1 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.(f)
10.1.2 Stock Purchase and Redemption Agreement dated March 31,
1998, among Dominion Cogen, Inc., Dominion Energy, Inc. and
Calpine Finance.(f)
10.2 Financing Agreements.
10.2.1 Calpine Construction Finance Company Financing Agreement
("CCFC I"), dated as of October 20, 1999.(j)
10.2.2 Calpine Construction Finance Company Financing Agreement
("CCFC II"), dated as of October 16, 2000.(p)(*)
10.2.3 Second Amended and Restated Credit Agreement dated as of May
23, 2000, among the Company, Bayerische Landesbank, as
Co-Arranger and Syndication Agent, The Bank of Nova Scotia,
as Lead Arranger and Administrative Agent, and the Lenders
named therein.(m)
10.3 Other Agreements.
10.3.1 Calpine Corporation Stock Option Program and forms of
agreements there under.(a)
29
32
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.3.2 Calpine Corporation 1996 Stock Incentive Plan and forms of
agreements there under.(b)
10.3.3 Calpine Corporation Employee Stock Purchase Plan and forms
of agreements there under.(b)
10.3.4 Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright.(b)
10.3.5 Executive Vice President Employment Agreement between
Calpine Corporation and Ms. Ann B. Curtis.(k)
10.3.6 Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Ron A. Walter.(k)
10.3.7 Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Robert D. Kelly.(k)
10.3.8 Executive Vice President Employment Agreement between
Calpine Corporation and Mr. Thomas R. Mason.(k)
10.4 Form of Indemnification Agreement for directors and
officers.(b)
12.1 Statement on Computation of Ratio of Earnings to Fixed
Charges.(*)
21 Subsidiaries of the Company.(*)
23.1 Consent of Arthur Andersen LLP, Independent Public
Accountants.(*)
23.2 Consent of Netherland, Sewell & Associates, Inc.,
independent engineer.(*)
23.3 Consent of McDaniel & Associates Consultants, Ltd.,
independent engineer.(*)
23.4 Consent of Gilbert Laustsen Jung Associates, Ltd.,
independent engineer.(*)
24 Power of Attorney of Officers and Directors of Calpine
Corporation (set forth on the signature pages of this
report).(*)
- ---------------
(a) Incorporated by reference to Registrant's Registration Statement on Form S-1
(Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Registration Statement on Form
S-1/A (Registration Statement No. 333-07497).
(c) Incorporated by reference to Registrant's Registration Statement on Form S-4
(Registration Statement No. 333-06259).
(d) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1996 and filed on May 14, 1996.
(e) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1997 and filed on August 14, 1997.
(f) Incorporated by reference to Registrant's Current Report on Form 8-K dated
March 31, 1998 and filed on April 14, 1998.
(g) Incorporated by reference to Registrant's Registration Statement on Form S-4
(Registration Statement No. 333-61047).
(h) Incorporated by reference to Registrant's Registration Statement on Form
S-3/A (Registration Statement No. 333-72583).
(i) Incorporated by reference to Registrant's Registration Statement on Form
S-3/A (Registration Statement No. 333-87427).
(j) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1999 and filed on February 29, 2000. Approximately 200 pages of
this exhibit have been omitted pursuant to a request for confidential
treatment. The omitted language has been filed separately with the
Securities and Exchange Commission.
(k) Incorporated by reference to Registrant's Form 10-Q/A dated September 30,
1999 and filed on November 17, 1999.
30
33
(l) Incorporated by reference to Registrant's Registration Statement on Form
8-A, amended by Calpine's Registration Statement on Form 8-A/A (Registration
Statement No. 001-12079).
(m) Incorporated by reference to Registrant's Current Report on Form 8-K dated
July 25, 2000 and filed on August 9, 2000.
(n) Incorporated by reference to Registrant's Registration Statement on Form S-3
(Registration Statement No. 333-33736).
(o) Incorporated by reference to Registrant's Registration Statement on Form S-3
(Registration Statement No. 333-47068).
(p) Approximately 71 pages of this exhibit have been omitted pursuant to a
request for confidential treatment. The omitted language has been filed
separately with the Securities and Exchange Commission.
(q) Incorporated by reference to Registrant's Registration Statement on Form S-4
(Registration Statement No. 333-41261).
(*) Filed herewith.
31
34
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.
CALPINE CORPORATION
Date: March 14, 2001 By: /s/ ANN B. CURTIS
------------------------------------
Ann B. Curtis
Executive Vice President and
Director
(Principal Financial Officer)
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS: That the undersigned officers and
directors of Calpine Corporation do hereby constitute and appoint Peter
Cartwright and Ann B. Curtis, and each of them, the lawful attorney and agent or
attorneys and agents with power and authority to do any and all acts and things
and to execute any and all instruments which said attorneys and agents, or
either of them, determine may be necessary or advisable or required to enable
Calpine Corporation to comply with the Securities and Exchange Act of 1934, as
amended, and any rules or regulations or requirements of the Securities and
Exchange Commission in connection with this Form 10-K Annual Report. Without
limiting the generality of the foregoing power and authority, the powers granted
include the power and authority to sign the names of the undersigned officers
and directors in the capacities indicated below to this Form 10-K Annual Report
or amendments or supplements thereto, and each of the undersigned hereby
ratifies and confirms all that said attorneys and agents, or either of them,
shall do or cause to be done by virtue hereof. This Power of Attorney may be
signed in several counterparts.
IN WITNESS WHEREOF, each of the undersigned has executed this Power of
Attorney as of the date indicated opposite the name.
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ PETER CARTWRIGHT Chairman, President, Chief March 14, 2001
- --------------------------------------------------- Executive and Director
Peter Cartwright (Principal Executive Officer)
/s/ ANN B. CURTIS Executive Vice President and March 14, 2001
- --------------------------------------------------- Director
Ann B. Curtis (Principal Financial Officer)
/s/ CHARLES B. CLARK, JR. Vice President and Corporate March 14, 2001
- --------------------------------------------------- Controller
Charles B. Clark, Jr. (Principal Accounting Officer)
/s/ JEFFREY E. GARTEN Director March 14, 2001
- ---------------------------------------------------
Jeffrey E. Garten
/s/ SUSAN C. SCHWAB Director March 14, 2001
- ---------------------------------------------------
Susan C. Schwab
32
35
SIGNATURE TITLE DATE
--------- ----- ----
/s/ GEORGE J. STATHAKIS Director March 14, 2001
- ---------------------------------------------------
George J. Stathakis
/s/ JOHN O. WILSON Director March 14, 2001
- ---------------------------------------------------
John O. Wilson
/s/ V. ORVILLE WRIGHT Director March 14, 2001
- ---------------------------------------------------
V. Orville Wright
Director
- ---------------------------------------------------
Michael Polsky
33
36
CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND OTHER INFORMATION
DECEMBER 31, 2000
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-33
Consolidated Balance Sheets December 31, 2000 and 1999...... F-34
Consolidated Statements of Operations for the Years Ended
December 31, 2000, 1999 and 1998.......................... F-35
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2000, 1999 and 1998.............. F-36
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999 and 1998.......................... F-37
Notes to Consolidated Financial Statements for the Years
Ended December 31, 2000, 1999 and 1998.................... F-38
F-1
37
CALPINE CORPORATION AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT EARNINGS PER SHARE AND RATIO DATA)
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
1996 1997 1998 1999 2000
---------- ---------- ---------- ---------- ----------
STATEMENT OF OPERATIONS DATA:
REVENUE:
Electricity and steam sales.............................. $ 199,464 $ 237,277 $ 507,897 $ 760,325 $1,702,320
Service contract revenue................................. 6,455 10,177 20,249 43,773 480,234
Income from unconsolidated investments in power
projects............................................... 6,537 15,819 25,240 36,593 24,639
Interest income on loans to power projects............... 2,098 13,048 2,562 1,226 4,827
Other revenue............................................ -- -- -- 5,818 70,773
---------- ---------- ---------- ---------- ----------
Total revenue...................................... 214,554 276,321 555,948 847,735 2,282,793
Cost of revenue(1)....................................... 132,762 156,343 378,926 561,850 1,558,676
---------- ---------- ---------- ---------- ----------
Gross profit........................................... 81,792 119,978 177,022 285,885 724,117
Project development expenses............................. 3,867 7,537 7,165 10,712 27,556
General and administrative expenses(1)................... 11,134 15,254 23,181 48,671 94,113
---------- ---------- ---------- ---------- ----------
Income from operations................................. 66,791 97,187 146,676 226,502 602,448
Interest expense......................................... 45,294 61,466 86,726 91,162 56,700
Distributions on trust preferred securities.............. -- -- -- 2,565 44,210
Other income............................................. (6,259) (17,438) (13,423) (25,441) (42,100)
---------- ---------- ---------- ---------- ----------
Income before provision for income taxes............... 27,756 53,159 73,373 158,216 543,638
Provision for income taxes............................... 9,064 18,460 27,054 61,973 218,951
---------- ---------- ---------- ---------- ----------
Income before extraordinary charge..................... 18,692 34,699 46,319 96,243 324,687
Extraordinary charge, net of tax benefit of $ --, $ --,
$441, $793 and $796.................................... -- -- 641 1,150 1,235
---------- ---------- ---------- ---------- ----------
Net income............................................. $ 18,692 $ 34,699 $ 45,678 $ 95,093 $ 323,452
========== ========== ========== ========== ==========
Basic earnings per common share:
Weighted average shares of common stock outstanding.... 103,221 159,569 160,969 209,314 264,799
Income before extraordinary charge..................... $ 0.18 $ 0.22 $ 0.29 $ 0.46 $ 1.23
Extraordinary charge................................... $ -- $ -- $ (0.01) $ (0.01) $ (0.01)
Net income............................................. $ 0.18 $ 0.22 $ 0.28 $ 0.45 $ 1.22
Diluted earnings per common share:
Weighted average shares of common stock outstanding
before dilutive effect of certain trust preferred
securities........................................... 119,030 168,128 169,311 222,644 280,776
Income before extraordinary charge and dilutive effect
of certain trust preferred securities................ $ 0.16 $ 0.21 $ 0.27 $ 0.43 $ 1.16
Dilutive effect of certain trust preferred
securities(2)........................................ $ -- $ -- $ -- $ -- $ (0.05)
Income before extraordinary charge..................... $ 0.16 $ 0.21 $ 0.27 $ 0.43 $ 1.11
Extraordinary charge................................... $ -- $ -- $ -- $ -- $ (0.01)
Net income............................................. $ 0.16 $ 0.21 $ 0.27 $ 0.43 $ 1.10
OTHER FINANCIAL DATA AND RATIOS:
EBITDA(3)................................................ $ 110,703 $ 172,026 $ 241,633 $ 351,528 $ 825,925
EBITDA to Consolidated Interest Expense(4)............... 2.29x 2.60x 2.61x 3.35x 6.66x
Total debt to EBITDA..................................... 5.43x 4.98x 4.43x 5.84x 5.44x
Ratio of earnings to fixed charges(5).................... 1.46x 1.72x 1.69x 1.77x 2.04x
BALANCE SHEET DATA:
Cash and cash equivalents................................ $ 95,970 $ 48,513 $ 96,532 $ 349,371 $ 588,698
Property, plant and equipment, net....................... 648,208 736,339 1,094,303 2,908,056 7,459,055
Investment in power projects............................. 13,936 222,542 221,509 243,225 205,621
Total assets....................................... 1,031,397 1,380,915 1,728,946 3,991,606 9,737,257
Short-term debt.......................................... 37,492 112,966 5,450 47,470 61,558
Long-term debt........................................... 563,640 742,893 1,065,940 2,006,190 4,430,357
Total debt......................................... 601,132 855,859 1,071,390 2,053,660 4,491,915
Company-obligated mandatorily redeemable convertible
preferred securities of subsidiary trusts.............. -- -- -- 270,713 1,122,490
Minority interests....................................... -- -- -- 61,705 37,576
Stockholders' equity..................................... 203,127 239,956 286,966 964,632 2,236,774
(The information contained in the Selected Consolidated Financial Data is
derived from the audited
Consolidated Financial Statements of Calpine Corporation and Subsidiaries.)
F-2
38
- ---------------
(1) Certain expenses for the years 1996 through 1999 have been reclassed from
general and administrative expenses to plant operating expenses to conform
with the 2000 presentation.
(2) Includes the effect of the assumed conversion of certain trust preferred
securities. For the year 2000, the assumed conversion calculation adds
31,746 shares of common stock and $20,841 to the net income results,
representing the after tax distribution expense on certain trust preferred
securities avoided upon conversion.
(3) EBITDA is defined as net income less income from unconsolidated investments,
plus cash received from unconsolidated investments, plus provision for tax,
plus interest expense, plus one-third of operating lease expenses, plus
depreciation and amortization, plus distributions on trust preferred
securities. 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). Prior to 2000, EBITDA had been calculated
according to an indenture definition. EBITDA for 1996 - 1999 has been
restated to conform to the definition set forth above.
(4) Consolidated Interest Expense is defined as total interest expense plus
one-third of all operating lease obligations and distributions on trust
preferred securities.
(5) For purposes of computing our consolidated ratio of earnings to fixed
charges, earnings consist of pretax income before adjustment for minority
interests in our consolidated subsidiaries or income or loss from equity
investees, plus fixed charges, amortization of capitalized interest, and
distributed income of equity investees, reduced by interest capitalized,
distributions on our company-obligated mandatorily redeemable convertible
preferred securities of subsidiary trusts ("HIGH TIDES") and the minority
interest in pretax income of subsidiaries that have not incurred fixed
charges. Fixed charges consist of interest expensed and capitalized
(including amortized premiums, discounts and capitalized expenses related to
indebtedness), an estimate of the interest within rental expense and the
distributions on our HIGH TIDES.
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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, including
statements regarding the intent, belief or current expectations of Calpine
Corporation ("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 that could
materially affect actual results such as, but not limited to, (i)changes in
government regulations, including pending changes in California, and anticipated
deregulation of the electric energy industry, (ii) commercial operations of new
plants that may be delayed or prevented because of various development and
construction risks, such as a failure to obtain financing and the necessary
permits to operate or the failure of third-party contractors to perform their
contractual obligations, (iii) cost estimates are preliminary and actual costs
may be higher than estimated, (iv) the assurance that the Company will develop
additional plants, (v) a competitor's development of a lower-cost generating
gas-fired power plant, (vi) the risks associated with marketing and selling
power from power plants in the newly competitive energy market, (vii) the risks
associated with marketing and selling combustion turbine parts and components in
the competitive combustion turbine parts market, (viii) the risks associated
with engineering, designing and manufacturing combustion turbine parts and
components, (ix) delivery and performance risks associated with combustion
turbine parts and components attributable to production, quality control,
suppliers and transportation, or (x) the successful exploitation of an oil or
gas resource that ultimately depends upon the geology of the resource, the total
amount and cost to develop recoverable reserves, and operational factors
relating to the extraction of natural gas. Prospective investors are also
cautioned that the California energy market remains uncertain. The Company's
management is working closely with a number of parties to resolve the current
uncertainty. This is an ongoing process and, therefore, the outcome cannot be
predicted. It is possible that any such outcome will include changes in
government regulations, business and contractual relationships or other factors
that could materially affect the Company. However, management believes that a
final resolution will not have a material adverse impact on the Company.
Prospective investors are also referred to the 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 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 March 8, 2001, we had interests in 50
operating power plants predominantly in the United States, representing 5,849
megawatts of net capacity.
On January 11, 2000, we announced our plans to expand our presence into the
Florida wholesale power market. Our plans are to invest approximately $850
million in power generation facilities and manage these development activities
in the Southeast from a new office in Tampa, Florida. We will develop two
natural gas-fired energy centers, the 590 megawatt Osprey Energy Center, to be
located in the City of Auburndale adjacent to an existing Calpine power
facility, and the 1,239 megawatt Blue Heron Energy Center, to be located outside
of Vero Beach. Construction for the proposed facilities is planned for 2001 and
2002, respectively, with the Osprey Energy Center to commence commercial
operation in the fall of 2003, followed by the Blue Heron Energy Center in mid
2004.
On January 14, 2000, we acquired a 296 megawatt net interest in the Aries
Power Plant, a 591 megawatt natural gas-fired plant currently under construction
near Pleasant Hill, Missouri, from a subsidiary of Aquila Energy Corporation.
Construction started in the fall of 1999 and commercial operation is scheduled
to begin in late 2001. The majority of the plant's output will be sold to
Missouri Public Service through May 2005. Thereafter, power will be sold into
the Southwest Power Pool.
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On January 18, 2000, we entered into an agreement to provide the Sacramento
Municipal Utility District ("SMUD") with a five-year supply of electricity from
our 547 megawatt Sutter Power Plant. The plant is currently under construction
near Yuba City, California. We will provide 150 megawatts of electricity to
SMUD's customer base beginning with the plant's startup in mid 2001.
On January 26, 2000, we completed a private offering under Rule 144A of the
Securities Act of 1933 of 6,000,000 5 1/2% Remarkable Term Income Deferrable
Equity Securities ("trust preferred securities" or "HIGH TIDES") issued by a
subsidiary trust at $50.00 each, raising $300.0 million of aggregate gross
proceeds. On February 10, 2000, we privately placed an additional 1,200,000
5 1/2% HIGH TIDES pursuant to the exercise of the purchasers' option generating
additional gross proceeds of $60.0 million.
On January 28, 2000, we acquired the development rights for the Hermiston
Power Project, a 630 megawatt gas-fired cogeneration power facility located near
Hermiston, Oregon, from Ida-West Energy Company and TransCanada Pipelines.
Construction of the facility commenced in the summer of 2000 and we expect that
commercial operation will commence in mid 2002.
On February 2, 2000, we announced plans to build, own and operate the
Decatur Energy Center, a 794 megawatt gas-fired cogeneration energy center at
Solutia Inc.'s Decatur, Alabama chemical facility. Under a 20-year contract,
Solutia will lease a portion of the facility to meet its electricity needs and
purchase its steam requirements from us. Excess power from the facility will be
sold into the Southeastern Wholesale Power Market under a variety of short,
medium, and long-term contracts. We will also build a new intrastate natural gas
pipeline to fuel the energy center. Construction began in September 2000 and
commercial operation is expected to commence in mid 2002.
On February 4, 2000, we acquired 100% of the stock of Western Gas Resources
California ("Western") from Western Gas Resources, Inc. for $14.9 million.
Western's assets include the 130-mile Steelhead natural gas pipeline and the
remaining interest in the Sacramento River Gas System natural gas pipeline, now
100% owned by us.
On February 8, 2000, we announced that the Towantic Energy Center received
approval through a town-wide referendum to purchase the town-owned land on which
the facility will be built. The referendum also approved a Tax Stabilization
Agreement that will even out the property taxes paid to the town of Oxford,
Connecticut over a 22-year period.
On February 9, 2000, we announced that the California Energy Commission
approved plans to construct the Delta Energy Center in Pittsburg, California.
The Delta Energy Center, an 874 megawatt gas-fired energy center located at the
Dow Chemical facility, is the first facility that will be developed, owned and
operated under a joint venture with Bechtel Enterprises, and will provide power
to Pittsburg, California and to the greater San Francisco Bay Area. We have a
437 megawatt net interest in this facility.
On February 22, 2000, we announced plans to build, own and operate the Lone
Oak Energy Center, a 915 megawatt gas-fired cogeneration facility located in
Lowndes County, Mississippi. We anticipate that construction will commence in
mid 2001 and that commercial operation of the facility will commence in the
spring of 2003.
On February 24, 2000, we announced plans to build, own and operate the
Hillabee Energy Center, a 770 megawatt gas-fired cogeneration facility located
in Tallapoosa County, Alabama. We anticipate that construction will commence in
mid 2001 and that commercial operation of the facility will commence in mid
2003.
On March 6, 2000, we announced that we entered into a partnership agreement
with Cleco Midstream Resources, an affiliate of Pineville, Louisiana-based Cleco
Corporation, to participate in the Acadia Energy Center. The partners plan to
build, own and operate the 1,239 megawatt natural gas-fired energy center near
Eunice, Louisiana. We have a 620 megawatt net interest in this facility.
Construction commenced in mid 2000 and commercial operation for the energy
center is expected in May 2002.
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On March 23, 2000, we announced plans to build, own and operate the
Wawayanda Energy Center, a 630 megawatt natural gas-fired facility to be located
near Middletown, New York. We anticipate that construction will begin in early
2002 and commercial operation will begin in early 2004.
On March 30, 2000, we purchased a 78.5%, or 394 megawatt, interest in the
502 megawatt Hidalgo Energy Center, located in Edinburg, Texas, from Duke Energy
North America for $235 million. The purchase included a cash payment of $134
million and the assumption of a $101 million capital lease obligation. The
facility began commercial operation on June 14, 2000. The Hidalgo Energy Center
sells power under our system approach into the Electric Reliability Council of
Texas' wholesale market and potentially may sell into northern Mexico in the
future.
On March 30, 2000, we announced a 50 megawatt expansion of the natural
gas-fired, cogeneration power plant located in Morris, Illinois. We also
announced the signing of a power sales agreement to deliver approximately 100
megawatts of capacity from the Morris Power Plant to Commonwealth Edison Company
through the end of 2000. The majority of the electricity and all of the steam
produced by the plant are sold to Equistar Chemicals, L.P. under a long-term
agreement that expires in 2023.
On April 20, 2000, we announced plans to construct the Calgary Energy
Centre. Scheduled to begin commercial operation in early 2003, the 300 megawatt
combined cycle, natural gas-fired facility was the first independent power
project announced in the Calgary area, and represents our first investment in
the Canadian power industry.
On May 16, 2000, we announced the establishment of a new business unit,
Calpine c*Power, to serve the rapidly growing worldwide demand for highly
reliable critical power. Highly reliable power adds to our growing line of
high-value energy products, which includes green power, ancillary services and
peaking power.
On May 22, 2000, we announced plans to purchase 36 F-class turbines from
Orlando, Florida-based Siemens Westinghouse Power Corporation. The agreement
includes long-term service programs and performance enhancements on existing
equipment. In 2003 and 2004, Siemens Westinghouse will be obligated to deliver a
total of 36 turbines to us. When operated in a combined cycle configuration, the
36 new turbines equate to approximately 9,800 additional megawatts of
electricity generation potential.
On May 23, 2000, we announced the acquisition of development rights to
build, own and operate the 700 megawatt natural gas-fired Fremont Energy Center
near Fremont, Ohio. Construction is scheduled to begin in mid 2001 and we expect
commercial operation to commence in mid 2003.
On May 23, 2000, we entered into an amended and restated $400 million,
three-year revolving line of credit led by The Bank of Nova Scotia, replacing an
expiring $100 million credit facility. The amended and restated facility will be
used for working capital and other general corporate purposes.
On May 31, 2000, we completed the acquisition of the remaining 50% interest
in the 105 megawatt Kennedy International Airport Power Plant ("KIAC") in
Queens, New York, and the 40 megawatt Stony Brook Power Plant located at the
State University of New York at Stony Brook on Long Island from Statoil Energy,
Inc. We paid approximately $71 million in cash and assumed a capital lease
obligation relating to the Stony Brook Power Plant. We initially acquired a 50%
interest in both facilities in December 1997.
On June 8, 2000, we effected a two-for-one split of our common stock for
stockholders of record as of May 29, 2000.
On June 15, 2000, we announced that we acquired the Freestone Energy Center
from New Orleans, Louisiana-based Entergy Corp. Freestone is a 1,052 megawatt
natural gas-fired energy center located in Freestone County, Texas, near
Fairfield, about 80 miles southeast of Dallas. The technologically advanced
energy center is currently under construction, with a two-phased commercial
start-up beginning in June 2002. We paid approximately $61.0 million in cash and
assumed certain liabilities. This represented payment for the land and
development rights for the Freestone Energy Center, previous progress payments
made for four General Electric gas turbines, two steam turbines and related
equipment, and development expenditures incurred to date.
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On June 27, 2000, we announced plans to build, own and operate a natural
gas-fired cogeneration energy center at the BP Amoco chemical facility in
Decatur, Alabama. The proposed Morgan Energy Center will generate approximately
790 megawatts of electricity in addition to supplying steam for BP Amoco's
facility. Construction began in September 2000 and we expect commercial
operation to commence in December 2002.
On June 29, 2000, we announced that we secured the rights to develop,
build, own and operate the Teayawa Energy Center, a 608 megawatt natural
gas-fired power generating facility near the town of Thermal in Riverside
County, California through a development agreement with Adair International Oil
and Gas, Inc. The Teayawa Energy Center will be sited on the Torres Martinez
Desert Cahuilla Indians' land through a long-term lease agreement with the
Torres Martinez. Commercial operation is expected in early 2004.
On June 30, 2000, we completed the acquisition from Edison Mission Energy
of the remaining 50% ownership interest in a 153 megawatt natural gas-fired,
combined cycle cogeneration facility located in Auburndale, Fla. We paid
approximately $22.0 million in cash and assumed certain liabilities, including
project level debt. Related to the project level debt was the assumption of an
interest rate swap agreement with a notional amount of $121.5 million at
December 31, 2000, which effectively converts the project level debt's floating
rate to a fixed rate of 6.52% per annum. We acquired an initial 50% ownership
interest in the Auburndale Power Plant in October 1997.
On July 5, 2000, we completed three acquisitions of natural gas reserves
for $206.5 million, including the acquisition of Calgary-based Quintana Minerals
Canada Corp. ("QMCC"), three fields in the Gulf of Mexico and natural gas assets
in the Piceance Basin, Colorado and onshore Gulf Coast. These acquisitions
increased our proven reserves to 430 bcfe, which at full production, can fuel
800 to 900 megawatts of combined cycle gas-fired power generation.
On July 6, 2000, we announced the addition of 100 megawatts of peaking
capacity to the natural gas-fired, cogeneration facility located in Auburndale,
Florida.
On July 18, 2000, we announced plans to purchase from GE Power Systems 21
model 7FB turbines which will produce an additional 5,250 megawatts of
electricity when operated in combined cycle mode. We will take delivery of 12
turbines in 2003, with the remainder of the contract to be filled in 2004.
On July 19, 2000, we announced we will develop, construct and own a natural
gas-fired, combined cycle power generation facility in Haywood County,
Tennessee. The proposed Haywood Energy Center represents our fourth project that
will interconnect with the Tennessee Valley Authority. The 915 megawatt facility
is scheduled to begin commercial operation in late 2004.
On July 20, 2000, we completed the acquisition of the Oneta Energy Center
from Panda Energy, International, Inc. Oneta is a 1,138 megawatt natural
gas-fired energy center under construction in Coweta, Oklahoma, southeast of
Tulsa. Under our agreement with Panda, we may be obligated to make certain
contingent payments during the operation of the Oneta facility. We also acquired
from Panda 24 General Electric 7 FA gas turbines and 12 steam turbines, of which
16 gas turbines and 8 steam turbines were subsequently repurchased by another
party in partnership with Panda.
On July 21, 2000, we signed a memorandum of understanding to purchase 85
heat recovery steam generators ("HRSG's") from St. Louis, Missouri-based
Nooter/Eriksen. We will begin taking delivery of the HRSG's in 2001, with the
bulk of the contract to be filled through 2004.
On July 24, 2000, we announced plans to enter into a $2.5 billion revolving
construction credit facility, through our wholly owned subsidiary Calpine
Construction Finance Company II, LLC ("CCFC II"), with a consortium of banks,
including The Bank of Nova Scotia and Credit Suisse First Boston as lead
arrangers. We signed this agreement during the fourth quarter of 2000.
On August 1 and 2, 2000, we announced the completion of consent
solicitations to effect certain amendments to six Indentures governing certain
outstanding Calpine public debt securities which are due in the years
2004 - 2009. Supplemental Indentures effecting such amendments were executed by
Calpine and the respective Trustees.
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On August 9, 2000, we completed a public offering of 23,000,000 shares of
our common stock at $34.75 per share. The gross proceeds were $799.3 million.
On August 9, 2000, we, through our wholly-owned subsidiary, Calpine Capital
Trust III, completed a private offering, under Rule 144A of the Securities Act
of 1933, of 10,350,000 5% HIGH TIDES at a price of $50.00 per share. The gross
proceeds from the offering were $517.5 million.
On August 10, 2000, we completed a public offering of $250.0 million of our
8 1/4% Senior Notes due 2005 and $750.0 million of our 8 5/8% Senior Notes due
2010. The 8 1/4% Senior Notes mature on August 15, 2005 and interest is payable
semi-annually. The 8 5/8% Senior Notes mature on August 15, 2010 and interest is
payable semi-annually.
On August 16, 2000, we acquired the remaining 80% interest in the Agnews
Power Plant, a 29 megawatt natural gas-fired, combined cycle facility located in
San Jose, California from GATX Capital Corporation for a total purchase price of
$4.9 million. We first acquired a 20% equity interest in the Agnews Power Plant
in 1990.
On August 31, 2000, we announced that we acquired the remaining 45% equity
interest in the Aidlin Power Plant from an affiliate of Sumitomo Corporation for
a total purchase price of $6.4 million. We initially acquired a 5% equity
interest in the Aidlin Power Plant in 1989, representing our first megawatt of
generation. That interest was increased to 55% with the acquisition of two other
partners' interests in 1999. Located in The Geysers region of northern
California, Aidlin is a 20 megawatt power plant.
On September 1, 2000, we completed a leveraged lease financing transaction
to provide the term financing for both Phase I and Phase II of the Pasadena,
Texas cogeneration project. Under the terms of the lease, we received $400.0
million in gross proceeds and recorded a deferred gain of approximately $65.0
million.
On September 21, 2000, we announced a five year power sales agreement with
Imperial Irrigation District ("IID"). Beginning May 2002, we will deliver 150
megawatts of electricity from our new 555 megawatt South Point Power Plant to
IID's southern California electric customers.
On October 12, 2000, we completed the acquisition of Northbrook,
Illinois-based SkyGen Energy LLC ("SkyGen") from Michael Polsky and Wisvest
Corporation ("Wisvest"), an affiliate of Wisconsin Energy Corp. The total
purchase price of $359.1 million included $294.2 million in cash and 2,117,742
shares of our common stock (which were valued in the aggregate at $64.9 million
at the signing of the Letter of Intent). Additionally, we agreed to the
assumption of certain recourse and non-recourse obligations of SkyGen, the
assumption of certain contingent obligations of Wisvest and Wisconsin Energy
Crop. on behalf of SkyGen, and the obligation to make certain additional
contingent payments for completion of certain project development milestones.
Under the terms of the agreement, we acquired three operating facilities, five
facilities under construction, 12 late-stage development projects and 16 project
stage development projects. In addition, we assumed purchase rights and progress
payments for 34 General Electric 7 FA gas turbines to power these projects.
On October 16, 2000, we jointly announced with EOG Resources, Inc. ("EOG")
the signing of a one year marketing agreement that links the daily price of
natural gas to the price of electricity. EOG agreed to sell 10 million cubic
feet of natural gas per day directly to us. The transaction became effective
January 1, 2001 and will terminate December 31, 2001.
On October 17, 2000, we announced plans to enter into a 400 megawatt
long-term power supply agreement with Pacific Gas & Electric Company ("PG&E")
that will provide competitively priced electricity for PG&E's northern
California customers. Electricity deliveries will begin July 1, 2001 and end
December 31, 2003.
On October 17, 2000, we announced that we presented plans, with Tampa,
Florida-based Seminole Electric Cooperative, Inc. ("Seminole"), to the Florida
Public Service Commission under which our proposed Osprey Energy Center will
supply electric power under contract to help meet Seminole's member systems'
power needs.
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On October 20, 2000, we jointly announced with Cleco Corporation, a
regional energy services company headquartered in Pineville, Louisiana, the
signing of a 20-year contract with Aquila Energy, a wholly owned subsidiary of
UtiliCorp United, for 580 megawatts of the output of the jointly owned Acadia
Energy Center currently under construction in Acadia Parish, Louisiana. We have
a 50% interest in Acadia Power Partners LLC, which owns the 1,239 megawatt
combined cycle plant currently under construction. The remaining 50% interest is
held by Cleco Midstream Resources LLC, a wholly owned subsidiary of Cleco. Under
terms of a tolling agreement, starting July 1, 2002, Aquila Energy will supply
the natural gas needed to generate 580 megawatts of electricity and will own and
market the produced power.
On October 23, 2000, we announced that we entered into a project
development agreement to build, own and operate a 1,100 megawatt natural
gas-fired energy center to be located on the Ohio River in Hamilton Township,
Lawrence County, Ohio. The proposed Lawrence Energy Center will represent a $510
million investment, with a target commercial operation date of December 2004.
On October 31, 2000, we announced that we entered into a long-term, natural
gas transportation and storage agreement with Kinder Morgan Texas Pipeline, Inc.
("KMTP"), a subsidiary of Kinder Morgan, Inc. We will have access to up to
375,000 MMBtu of firm natural gas transportation service per day from KMTP for a
period of 10 years. The agreement began on January 1, 2001.
On October 31, 2000, we announced with Aquila Energy, a wholly-owned
subsidiary of UtiliCorp United, the completion of a $270 million construction
and leverage lease financing of the Aries Power Plant, a 591 megawatt gas-fired
power plant under construction in Pleasant Hill, Missouri. The majority of the
plant's capacity and electrical output has already been sold under a four year
contract (June 2001 - May 2005) to Missouri Public Service, a division of
UtiliCorp. Under the terms of separate tolling contracts, we, together with
Aquila, will purchase the balance of the plant's capacity and output,
remarketing it into the Southwest Power Pool and Southeast Electric Reliability
Counsel regional power markets. The marketing and fuel supply responsibilities
will be handled by Aquila.
On November 14, 2000, we effected a two-for-one split of our common stock
for stockholders of record as of November 6, 2000.
On November 15, 2000, we announced that our wholly owned subsidiary,
SkyGen, entered into an agreement to supply CP&L Energy ("CP&L") additional
power produced from the Broad River Energy Center expansion project. This
expansion, the second phase of construction of the Broad River Energy Center,
involves the installation of two additional combustion turbines capable of
producing an additional 360 megawatts of peaking power. Construction is expected
to be completed in the spring of 2001. The output will be sold to CP&L under
long-term power purchase agreements.
On November 15, 2000, we acquired TriGas Exploration, Inc. ("TriGas"), a
Calgary-based oil and gas company, for a total purchase price of $101.1 million.
The purchase price included cash payments of $79.6 million, as well as assumed
net indebtedness of $21.5 million. The acquisition provides us with natural gas
reserves to fuel our proposed Calgary Energy Centre, and a 26.6% working
interest in the East Crossfield Gas Plant, extensive pipelines and gathering
systems and a significant undeveloped land base with development potential.
On December 12, 2000, we announced that we are considering plans to develop
and operate a new energy-efficient electric generating facility in an effort to
meet a portion of the fast-growing local and regional electricity needs in
northern California. We are preparing technical studies for the proposed 1,065
megawatt facility. The proposed East Altamont Energy Center will be located in
the northeastern corner of Alameda County, and situated in an area dominated by
major regional high voltage transmission lines, a natural gas compressor
station, wind power generators, and the substantial pumping stations associated
with the California Aqueduct and the Delta-Mendota Canal. Upon completion of
licensing through the California Energy Commission, construction would begin in
June 2002, with commercial operation beginning in June 2004.
On December 13, 2000, we completed the acquisition of Boca Raton,
Florida-based Power Systems Mfg. LLC ("PSM"), an industry leader in combustion
turbine component engineering, design and manufacturing, for a total purchase
price of $16.3 million. The purchase price included cash payments of $5.6
million and
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281,189 shares of Calpine common stock (which were valued at $10.7 million at
the closing of the agreement). Additionally, the agreement provides for five
equal installments of cash payments totaling $26.7 million, beginning in January
2002, contingent upon future PSM performance. PSM will operate as a subsidiary
of Calpine and will continue to sell its products to the combustion turbine
market.
On December 15, 2000, we completed the acquisition of strategic power
assets from Dartmouth, Massachusetts-based Energy Management, Inc. ("EMI") for a
total purchase price of $145.0 million and the assumption of project financings.
The purchase price included cash payments of $100.0 million and 1,102,601 shares
of Calpine common stock (which were valued in the aggregate at $45.0 million at
the closing of the agreement). Under the terms of the agreement, we acquired the
remaining interest in three recently constructed combined cycle power generating
facilities located in Dighton, Massachusetts, Tiverton, Rhode Island, and
Rumford, Maine, as well as Calpine-EMI Marketing LLC, a joint marketing venture
between Calpine and EMI.
On December 18, 2000, we announced with PG&E Corporation an agreement under
which we will acquire the Otay Mesa Generating Project in San Diego County. In
accordance with the terms of the agreement, we will build, own and operate the
618 megawatt generating facility, and PG&E Corporation's National Energy Group
will contract for up to 250 megawatts of the project's output. Construction is
expected to begin in the fall of 2001.
On December 19, 2000, we completed leveraged lease transactions in which we
sold the Tiverton, Rhode Island and Rumford, Maine facilities (purchased from
EMI) to a single owner lessor for $466.7 million, which then leased the
facilities back to our Tiverton and Rumford subsidiaries. We have fully and
unconditionally guaranteed all of the obligations of the Tiverton and Rumford
subsidiaries under the leases and other lease documents related to their lease
of the facilities from the owner lessor. The owner lessor paid the purchase
price for the facilities through an equity investment and by issuing notes. The
notes were purchased by a pass through trust created by the Tiverton and Rumford
subsidiaries. The purchase of the notes was financed by the private placement
under Rule 144A of the Securities Act of 1933 by the pass through trust of
$366.0 million in 9.0% pass through certificates due July 15, 2018.
On December 22, 2000, we completed a leveraged lease financing transaction
of our West Ford Flat and Bear Canyon projects. Under the terms of the
agreement, the facilities were incorporated into Calpine's Geothermal lease
facility, which we originally entered into on May 7, 1999. We received $81.0
million in gross proceeds and recorded a deferred loss of approximately $8.1
million, which is being amortized as an increase of operating lease expense over
the remaining life of the lease.
TRANSACTIONS ANNOUNCED OR CONSUMMATED SUBSEQUENT TO DECEMBER 31, 2000, AND
RECENT DEVELOPMENTS
On January 11, 2001, we jointly announced with Western Hub Properties LLC
("WHP") that WHP's wholly owned subsidiary, Lodi Gas Storage, LLC, entered into
a long-term firm agreement to supply Calpine with storage services at WHP's Lodi
Gas Storage facility near Lodi, California. The storage arrangement can provide
up to 4 billion cubic feet (bcf) of working gas inventory and daily
deliverability equal to approximately 20 percent of our western region peak day
gas requirements in 2002. The Lodi Gas Storage Project, located approximately 50
miles east of San Francisco, is slated to begin construction in February of
2001, and to begin operation early in the fourth quarter of 2001.
On January 17, 2001, our wholly owned subsidiary, SkyGen, announced plans
to build, own and operate an 850 megawatt natural gas-fired cogeneration
facility in Augusta, Georgia. The proposed Augusta Energy Center will be fueled
by clean natural gas and will supply energy to DSM Chemicals North America, Inc.
for use in its production processes. Construction is expected to begin in the
third quarter of 2001.
On January 26, 2001, we announced the acquisition of the development rights
from Cogentrix, an independent power company based in North Carolina, for the
577 megawatt Washington Parish Energy Center, located near Bogalusa, Louisiana.
We are managing construction of the facility, which began in January 2001.
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On February 8, 2001 we announced plans to acquire all of the common shares
of Encal Energy Ltd. ("Encal"), a Calgary, Alberta-based natural gas and
petroleum exploration and development company, through a stock-for-stock
exchange in which Encal shareholders will receive Cdn. $12.00 per share in
Calpine common equivalent shares based on an exchange ratio to be determined
prior to closing. The aggregate value of the transaction, for which we expect to
use pooling of interests accounting, is approximately $1.2 billion, including
the assumed net indebtedness of Encal. Upon completion of the acquisition, we
will gain approximately 1.0 trillion cubic feet equivalent of proved and
probable natural gas reserves, net of royalties. This transaction also provides
access to firm gas transportation capacity from western Canada to California and
the eastern U.S., and an accomplished management team capable of leading our
business expansion in Canada. With the addition of Encal's assets, which
currently produce approximately 230 million cubic feet of gas equivalent
("mmcfe") per day, net of royalties, our net production is expected to increase
to 390 mmcfe per day in North America, enough to fuel approximately 2,300
megawatts of our power fleet. We expect to close this transaction during the
second quarter of 2001.
On February 12, 2001, we announced that the Florida Public Service
Commission approved a joint application filed by Calpine and Seminole Electric
Cooperative, Inc., under which we will build a 590 megawatt combined cycle power
generating facility, the Osprey Energy Center, to supply electric power to help
meet Seminole's members' power needs.
On February 13, 2001, we announced that our wholly owned subsidiary,
SkyGen, entered into an agreement to supply Alliant Energy's Wisconsin Power &
Light Co. ("WP&L") 453 megawatts of electric capacity and energy from the
proposed 600 megawatt RiverGen Energy Center, which will be located next to
WP&L's existing power plant near Beloit, Wisconsin. The power sales agreement is
for a term of ten years. Construction of the RiverGen Energy Center is expected
to begin during the fourth quarter of 2001, with commercial operation scheduled
for late 2003.
On February 15, 2001, we completed a public offering of $1.15 billion of
our 8 1/2% Senior Notes due 2011. The Senior Notes due 2011 bear interest at
8 1/2% per year, payable semi-annually and mature on February 15, 2011.
Recent Developments in the California Power Market. The deregulation of the
California power market has produced significant unanticipated results in the
past year. The deregulation froze the rates that utilities can charge their
retail and business customers in California and prohibited the utilities from
buying power on a forward basis, while wholesale power prices were not subjected
to limits.
In the past year, a series of factors have reduced the supply of power to
California, which has resulted in wholesale power prices that have been
significantly higher than historical levels. Several factors contributed to this
increase. These included:
- significantly increased volatility in prices and supplies of natural gas;
- an unusually dry fall and winter in the Pacific Northwest, which reduced
the amount of available hydroelectric power from that region (typically,
California imports a portion of its power from this source);
- the large number of power generating facilities in California nearing the
end of their useful lives, resulting in increased downtime (either for
repairs or because they have exhausted their air pollution credits and
replacement credits have become too costly to acquire on the secondary
market); and
- continued obstacles to new power plant construction in California, which
deprived the market of new power sources that could have, in part,
ameliorated the adverse effects of the foregoing factors.
As a result of this situation, two major California utilities that are
subject to the retail rate freeze, including Pacific Gas & Electric Company
("PG&E"), have faced wholesale prices that far exceed the retail prices they are
permitted to charge. This has led to significant underrecovery of costs by these
utilities; and they have been widely reported to be facing the prospect of
insolvency. As a consequence, these utilities have defaulted under a variety of
contractual obligations, including payment obligations to power generators. PG&E
F-11
47
has defaulted on payment obligations to us (See Notes 15 and 19 of the Notes to
Consolidated Financial Statements).
We have historically sold power to PG&E, which is one of the California
utilities that is subject to the rate freeze. We are currently selling power to
PG&E pursuant to long-term qualifying facility ("QF") contracts, which are
subject to federal regulation under the Public Utility Regulatory Policies Act
of 1978, as amended ("PURPA") (16 U.S.C. sec. 796 et seq.). The QF contracts
provide that the California Public Utilities Commission ("CPUC") determines the
appropriate utility "avoided cost" to be used to set energy payments for certain
QF contracts, including those for all of our QF plants in California which sell
power to PG&E. Section 390 of the California Public Utility Code provided QFs
the option to elect to receive energy payments based on the California Power
Exchange ("PX") market clearing price. In mid-2000, our QF facilities elected
this option and were paid based upon the PX zonal day ahead clearing price ("PX
Price") from summer 2000 until January 19, 2001, when the PX ceased operating a
day ahead market. Since that time, the CPUC has ordered that the price to be
paid for energy deliveries by QFs electing the PX Price shall be based on a
natural gas cost-based "transition formula." The CPUC has conducted proceedings
(R. 99-11-022) to determine whether the PX Price was the appropriate price for
the energy component upon which to base payments to QFs which had elected the PX
based pricing option. It is possible that the CPUC could order a payment
adjustment based on a different energy price determination. We believe that the
PX Price was the appropriate price for energy payments but there can be no
assurance that this will be the outcome of the CPUC proceedings. Legislation has
recently been introduced in the California legislature (SB 47X) that would
establish a fixed price for the QF contracts for a 5 year period and would
eliminate any PX Price adjustment prior to December 31, 2000. There can be no
assurances that this legislation will be enacted.
We have continued to honor our contractual obligations to PG&E under our QF
contracts. To date, we have refrained from pursuing our collection remedies with
respect to PG&E's default, however, we have been actively involved with the
California utilities, the California legislature, and other interested parties
to develop legislation designed to stabilize energy prices through the
application of a long-term energy pricing methodology (for a five-year period)
in place of the short-term pricing methodology currently utilized under the QF
contracts, as discussed above. We also expect further legislation to enable the
California utilities to finance over a longer term the difference between the
wholesale prices that have been paid and the retail prices they received during
last fall and into this winter. We believe that this should further enhance
PG&E's ability to make payment of all past due amounts. However, management
cannot predict the timing or ultimate outcome of the legislative process or the
payment of amounts due under our contracts.
As this situation has deteriorated, California has taken steps to restore a
predictable and reliable power market to the State. Recently, California adopted
legislation permitting it to issue long-term revenue bonds to provide funding
for wholesale purchases of power. The bonds will be repaid with the proceeds of
payments by retail customers over time. The California Department of Water
Resources ("DWR") sought bids for long-term power supply contracts. We
successfully bid in that auction, and announced, as indicated below, that we
have signed three significant long-term power supply contracts with DWR.
On February 7, 2001, we announced the signing of a 10-year, $4.6 billion
fixed-price contract with DWR to provide electricity to the State of California.
We committed to sell up to 1,000 megawatts of electricity, with initial
deliveries of 200 megawatts starting October 1, 2001, and increasing to 1,000
megawatts by January 1, 2004. This contract will continue through 2011. The
electricity will be sold directly to DWR on a 24-hour, 7-day-a-week basis.
On February 28, 2001, we announced the signing of two long-term power sales
contracts with DWR. Under the terms of the first contract, a $5.2 billion,
10-year, fixed-price contract, we commit to sell up to 1,000 megawatts of
generation. Initial deliveries are scheduled to begin July 1, 2001 with 200
megawatts and increase to 1,000 megawatts by as early as July 2002. Under the
terms of the second contract, a 20-year contract totaling up to $3.1 billion, we
will supply DWR with up to 495 megawatts of peaking generation, beginning with
90 megawatts as early as August 2001, and increasing up to 495 megawatts as
early as August 2002.
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On March 13, 2001, we announced the signing of a two-month deal to provide
555 megawatts of electricity to DWR effective immediately through May 15, 2001.
FERC Investigation into California Wholesale Markets. Beginning in May 2000,
wholesale energy prices in the California markets increased to levels well above
1999 levels. In response, on June 28, 2000, the ISO Board of Governors reduced
the price cap applicable to the ISO's wholesale energy and ancillary services
markets from $750/MWh to $500/MWh. The ISO subsequently reduced the price cap to
$250/MWh on August 1, 2000. During this period, however, the California Power
Exchange Corporation ("PX") maintained a separate price cap set at a much higher
level applicable to the "day-ahead" and "day-of" markets administered by the PX.
On August 23, 2000, the FERC denied a complaint filed August 2, 2000 by San
Diego Gas & Electric Company ("SDG&E") that sought to extend the ISO's $250
price cap to all California energy and ancillary service markets, not just the
markets administered by the ISO. However, in its order denying the relief sought
by SDG&E, the FERC instructed its staff to initiate an investigation of the
California power markets and to report its findings to the FERC and held further
hearing procedures in abeyance pending the outcome of this investigation.
On November 1, 2000, the FERC released a Staff Report detailing the results
of the Staff investigation, together with an "Order Proposing Remedies for
California Wholesale Markets" ("November 1 Order"). In the November 1 Order, the
FERC found that the California power market structure and market rules were
seriously flawed, and that these flaws, together with short supply relative to
demand, resulted in unusually high energy prices. The November 1 Order proposed
specific remedies to the identified market flaws, including: (a) imposition of a
so-called "soft" price cap at $150/MWh to be applied to both the PX and ISO
markets, which would allow bids above $150/MWh to be accepted, but will subject
such bids to certain reporting obligations requiring sellers to provide cost
data and/or identify applicable opportunity costs and specifying that such bids
may not set the overall market clearing price, (b) elimination of the
requirement that the California utilities sell into and buy from the PX, (c)
establishment of independent non-stakeholder governing boards for the ISO and
the PX, and (d) establishment of penalty charges for scheduling deviations
outside of a prescribed range. In the November 1 Order the FERC established
October 2, 2000, the date 60 days after the filing of the SDG&E complaint, as
the "refund effective date." Under the November 1 Order, rates charged for
service after that date through December 31, 2002 will remain subject to refund
if determined by the FERC not to be just and reasonable. While the FERC
concluded that the Federal Power Act and prior court decisions interpreting that
act strongly suggested that refunds would not be permissible for charges in the
period prior to October 2, 2000, it noted that it was willing to explore
proposals for equitable relief with respect to charges made in that period. All
of the Company's receivables from PG&E relate to energy generated by QF
facilities. Under FERC regulations, QF contracts are exempt from regulation
under the Federal Power Act, which is the legislation that provides the
authority for the FERC to compel refunds or frame other equitable relief with
respect to the California wholesale markets. See "Government
Regulation -- Federal Energy Regulation -- Federal Power Act Regulation."
Therefore, the Company believes that any refund or other equitable remedy that
the FERC may impose with respect to the California wholesale markets will not
affect the Company's ability to pursue payment by PG&E of all past due amounts
as described above.
On December 15, 2000, the FERC issued a subsequent order that affirmed in
large measure the November 1 Order (the "December 15 Order"). Various parties
have filed requests for administrative rehearing and for judicial review of
aspects of the FERC's December 15 Order. The outcome of these proceedings, and
the extent to which the FERC or a reviewing court may revise aspects of the
December 15 Order or the extent to which these proceedings may result in a
refund of or reduction in the amounts charged by the Company's subsidiaries for
power sold in the ISO and PX markets, cannot be determined at this time.
F-13
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SELECTED OPERATING INFORMATION
Set forth below is certain selected operating information for our power
plants and steam fields, for which results are consolidated in our statements of
operations. Results vary for the twelve months ended December 31, 2000, as
compared to the same period in 1999 and 1998, primarily due to the consolidation
of acquisitions, favorable energy pricing, and increased production. Electricity
revenue is composed of fixed capacity payments, which are not related to
production, and variable energy payments, which are related to production.
Capacity revenues include, besides traditional capacity payments, other revenues
such as Reliability Must Run and Ancillary Service revenues. The information set
forth under thermal and other revenue consists of the results for the Thermal
Power Company Steam Fields prior to the acquisition of the PG&E power plants on
May 7, 1999, in addition to host thermal sales and other revenue. As a result of
this acquisition, steam output was used to produce electricity, whereas this
output was previously sold to third parties.
YEARS ENDED DECEMBER 31,
----------------------------------------------------------------
1996 1997 1998 1999 2000
---------- ---------- ---------- ----------- -----------
(DOLLARS IN THOUSANDS, EXCEPT PRODUCTION AND PRICING DATA)
POWER PLANTS:
Electricity and steam revenues:
Energy........................... $ 97,997 $ 116,577 $ 334,549 $ 458,593 $ 1,219,495
Capacity......................... $ 63,549 $ 75,588 $ 123,380 $ 247,620 $ 383,528
Thermal and Other................ $ 37,918 $ 45,112 $ 49,968 $ 54,112 $ 99,297
Megawatt hours produced.......... 1,985,404 2,158,008 9,864,080 14,802,709 22,749,588
Average energy price per megawatt
hour.......................... $ 49.36 $ 54.02 $ 33.92 $ 30.98 $ 53.61
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Revenue -- Total revenue increased 169% to $2,282.8 million in 2000
compared to $847.7 million in 1999, primarily due to the impact of recognition
of a full year's income from various assets that were acquired in 1999,
recognition of a partial year's income from various assets that were acquired in
2000, increased production, and favorable energy pricing.
Electricity and steam sales increased 124% to $1,702.3 million in 2000
compared to $760.3 million in 1999. Approximately $269.4 million of the
increase was generated by a full year's activity of our geothermal
facilities, which we initially acquired in May 1999. The facilities that we
acquired as part of the Cogeneration Corporation of America, Inc. ("CGCA")
acquisition in December 1999 contributed $107.2 million in 2000.
Additionally, commencement of commercial operations at our Hidalgo facility
and of our Pasadena expansion generated approximately $147.1 million. Our
acquisitions of KIAC, Stony Brook, Auburndale, and Agnews during 2000,
contributed an additional $113.5 million to the overall increase in
revenues. The balance was primarily due to increased production and
favorable energy pricing in various markets, particularly California.
Service contract revenue increased 996% to $480.2 million in 2000
compared to $43.8 million in 1999. The $436.4 million increase was
primarily due to increased electric energy and gas hedging and related
activity associated with purchased power and gas sold to third parties.
Income from unconsolidated investments in power projects decreased 33%
to $24.6 million in 2000 compared to $36.6 million in 1999. Approximately
$5.2 million of the decrease is primarily attributable to the consolidation
of KIAC, Stony Brook, Auburndale, and Agnews' results in electricity and
steam sales as a result of our purchase of these facilities during 2000. We
also recorded $8.8 million less equity income from Sumas, and $1.2 million
less from our investment in Bayonne. These amounts were partially offset by
$4.7 million of revenue that we recorded in connection with our investment
in the Grays Ferry facility that we acquired in December 1999.
F-14
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Interest income on loans to power projects increased 300% to $4.8
million in 2000 compared to $1.2 million in 1999. Revenue recognized during
2000 related substantially to interest on loans to the Dighton, Tiverton,
and Rumford projects before we purchased the remaining interests in the
projects in December 2000. In 1999, we recorded $1.2 million of income from
our 20% investment in Sheridan California Energy, Inc. We no longer
recognize this revenue following our purchase of the remaining 80% interest
through the acquisition of Sheridan Energy, Inc., the parent of Sheridan
California Energy, Inc., in October 1999.
Other revenue was $70.8 million in 2000 compared to $5.8 million in
1999. This primarily represents revenues derived from the sale of natural
gas to third parties. The increase is attributable to the acquisition of
Sheridan Energy, Inc. in October 1999, in addition to several strategic gas
acquisitions during 2000, including Quintana and TriGas.
Cost of revenue -- Cost of revenue increased to $1,558.7 million in 2000
compared to $561.9 million in 1999, an increase of $996.8 million, or 177%.
Fuel expenses increased by $344.2 million to $612.9 million in 2000
compared to $268.7 million in 1999 due primarily to the incremental effect
of acquisitions made in 1999 such as the CogenAmerica facilities which
reflect a full year of activity in 2000, and due to acquisitions made in
2000. Additionally, we incurred significantly higher gas prices during
2000.
Plant operating expenses increased by $97.5 million to $220.2 million
in 2000 compared to $122.7 million in 1999 due primarily to the incremental
effect of acquisitions made in 1999 such as the CogenAmerica facilities and
the geothermal facilities which reflect a full year of activity in 2000,
and due to acquisitions made in 2000.
Depreciation expense increased by $71.5 million to $154.3 million in
2000 compared to $82.8 million in 1999 primarily due to an approximate
$39.2 million increase in depreciation expense relating to our natural gas
production. The remainder is substantially the result of the incremental
effect of acquisitions that we made during 1999 and 2000.
Production royalties increased by $18.5 million to $32.3 million in
2000 compared to $13.8 million in 1999 primarily due to royalties paid to
third parties in connection with geothermal energy generation.
Operating lease expenses increased by $35.8 million to $69.4 million
in 2000 compared to $33.6 million in 1999. Approximately $15.0 million was
due to the lease associated with our acquisition of the remaining 50%
interest in KIAC in May 2000. Another $8.7 million was due to the inclusion
of a full year's operations of our geothermal facilities, $5.0 million was
attributable to the Pasadena sales-leaseback that we entered into in
September 2000, and $6.4 million was due to the higher contingent lease
payments at our Watsonville facility.
Service contract expenses increased by $429.3 million to $469.5
million in 2000 compared to $40.2 million in 1999 due to costs associated
with increased electric energy and gas hedging and related activity
associated with power and gas purchased from third parties.
Project development expense increased by $16.9 million, or 158%, in 2000 to
$27.6 million compared to $10.7 million in 1999 due to heavier activities in
identifying and obtaining acquisition and project development opportunities
resulting from a larger number of development projects. For additional
information, see "Item 1 -- Business -- Project Development and Acquisitions."
General and administrative expenses -- In 2000, general and administrative
expenses were $94.1 million compared to $48.7 million in 1999. The increase of
93% or $45.4 million is largely attributable to our acquisitions and continued
organic growth in personnel and associated overhead costs necessary to support
the overall growth of our operations and construction programs.
Interest expense -- Interest expense before capitalization of interest was
$263.7 million in 2000 compared to $138.5 million in 1999, an increase of $125.2
million due to higher debt balances in 2000. Total debt increased by
approximately $2.4 billion due primarily to our public offering of $1 billion of
senior notes in
F-15
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August 2000 and due to debt acquired in connection with various acquisitions
such as capital leases associated with our Hidalgo, Agnews, and Stony Brook
acquisitions. After capitalization of interest on our significant construction
program (see "Item 1 -- Business -- Project Development and Acquisitions"), our
interest expense decreased by approximately $34.5 million in 2000 to $56.7
million from $91.2 million in 1999.
Distributions on Trust Preferred Securities -- Distributions on trust
preferred securities increased to $44.2 million in 2000 from $2.6 million in
1999, due to a full year of distributions on our HIGH TIDES issuance of November
1999, in addition to HIGH TIDES II and III issuances in January and August 2000,
respectively.
Interest income -- In 2000, interest income was $39.9 million compared to
$24.1 million in 1999. The increase of 66% or $15.8 million is attributable to
higher average cash balances in 2000 owing to the public offerings of senior
notes and common stock in August 2000, and due to the public offerings of HIGH
TIDES in January and August of 2000.
Other income, net -- In 2000, other income was $4.9 million compared to
$1.3 million in 1999. Approximately $2.0 million relates to the income recorded
from interest rate swaps that were extinguished in connection with the repayment
of Pasadena project level debt in September 2000, and $1.3 million pertains to a
business interruption insurance recovery at our Texas City project.
Provision for income taxes -- The effective income tax rate was
approximately 40% in 2000 compared to approximately 39% in 1999. In 2000 our
provision for federal and state income taxes totaled $219.0 million versus $62.0
million in 1999, an increase of $157.0 million, which is due primarily to higher
taxable income in 2000.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Revenue -- Total revenue increased 52% to $847.7 million in 1999 compared
to $555.9 million in 1998, primarily due to the impact of recognizing a full
year's income from various assets that were acquired in 1998 and of recognizing
a partial year's income from various assets that were acquired in 1999, as
described below.
Electricity and steam sales increased 50% to $760.3 million in 1999
compared to $507.9 million in 1998. Geothermal revenues at the Geysers
accounted for $123.2 million, or roughly half, of the total increase of
$252.4 million. This was primarily due to the purchase of 14 geothermal
power plants from PG&E on May 7, 1999 and, to a much lesser extent, due to
the purchases of: (1) an additional 50% stake in the Aidlin Power Plant in
August, 1999 after which we consolidated the plant into our financial
results; and (2) the Calistoga Power Plant on October 19, 1999. In 1999 our
geothermal steamfield sales of steam declined by $3.0 million compared to
1998, due to consolidation of steamfield and power plant operations at the
Geysers under Calpine ownership in May 1999, after which we stopped
recording revenues from geothermal steamfield sales to third parties.
The remainder of the increase in electricity and steam sales is
attributable to our gas fired power plants. In California, the Gilroy Power
Plant increased its revenue in 1999 by $27.9 million over 1998 by both (1)
doubling its production, mostly as a result of the expiration of PG&E's
curtailment rights on December 31, 1998 and (2) restructuring its power
purchase agreement with PG&E, effective as of September 1, 1999. Also, the
Pittsburg Power Plant in California increased its revenue by $12.6 million
in 1999 versus 1998. We acquired the project on July 21, 1998 and did not
have a full year of operations in 1998. In Texas, the Texas City and Clear
Lake Power Plants, which were consolidated into our financial statements
following the acquisition of the remaining 50% interest of Texas
Cogeneration Company ("TCC") on March 31, 1998, benefited by a full year of
operations in 1999 versus only nine months on a consolidated basis in 1998,
and together they recorded an additional $39.0 million of revenue in 1999
versus in 1998. And finally the Pasadena Power Plant, which commenced
operation in July 1998, had $43.6 million of additional revenue in 1999
compared to 1998 due to a full year of operations in 1999.
Service contract revenue increased 117% to $43.8 million in 1999
compared to $20.2 million in 1998. The $23.6 million increase was primarily
due to an increase in recorded sales of purchased power to third parties
and to an increase in sales of purchased gas to third parties.
F-16
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Income from unconsolidated investments in power projects increased 45%
to $36.6 million in 1999 compared to $25.2 million in 1998. The increase of
$11.4 million is primarily attributable to an increase of equity income
from the Sumas Power Plant. In 1999 we recorded $21.8 million versus $11.7
million in 1998, an increase of $10.1 million. Additionally, as a group,
our equity income projects on the East Coast, Lockport Power Plant, Stony
Brook Power Plant, Kennedy International Airport Power Plant, Gordonsville
Power Plant, Auburndale Power Plant, and Bayonne Power Plant, increased by
$4.2 million. This was offset by a $2.9 million reduction in equity income
attributable to our Clear Lake and Texas City Power Plants, which were
unconsolidated investments for part of 1998 until our purchase of the
remaining 50% interest in TCC on March 31, 1998.
Interest income on loans to power projects decreased 54% to $1.2
million in 1999 compared to $2.6 million in 1998. In 1999 we no longer
received interest income associated with the TCC investment following our
purchase of the remaining 50% interest in TCC on March 31, 1998. In 1999,
we recorded $1.2 million of income from our 20% investment in Sheridan
California Energy, Inc. We no longer recognize this revenue following our
purchase of the remaining 80% interest through the acquisition of Sheridan
Energy, the parent of Sheridan California Energy, Inc., on October 1, 1999.
Other revenue was $5.8 million in 1999 compared to none in 1998. In
1999 we recorded $5.3 million of oil and gas revenue following our
acquisition of Sheridan Energy on October 1, 1999.
Cost of revenue -- Cost of revenue increased to $561.9 million in 1999
compared to $378.9 million in 1998, an increase of $183.0 million, or 48%.
Fuel expenses increased by $87.1 million to $268.7 million in 1999
compared to $181.6 million in 1998 due primarily to: (1) a full year of
consolidated operations in 1999 for the Clear Lake and Texas City Power
Plants versus only nine months in 1998; (2) a full year of operations in
1999 versus a partial year in 1998 for the Pasadena Power Plant, which
commenced commercial operations in July, 1998; (3) a full year of
operations in 1999 versus a partial year in 1998 for the Pittsburg Power
Plant, which we acquired on July 21, 1998; and (4) higher production in
1999 compared to 1998, and therefore higher fuel expense, at our Gilroy and
King City Power Plants due to the expiration of PG&E's curtailment rights
on December 31, 1998 and April 28, 1999 respectively.
Plant operating expenses increased by $44.6 million to $122.7 million
in 1999 compared to $78.1 million in 1998 due primarily to higher
geothermal plant operating expense in 1999 following our purchase of 14
geothermal power plants from PG&E on May 7, 1999 and our purchase of
geothermal steam field assets from Unocal Corporation on March 19, 1999.
Depreciation expense increased by $8.8 million to $82.8 million in
1999 compared to $74.0 million in 1998 primarily due to a full year of
operations in 1999 versus partial years in 1998 for the Texas City, Clear
Lake and Pasadena Power Plants, as noted above, and also due to our
purchase of Sheridan Energy on October 1, 1999.
Production royalties increased by $3.1 million to $13.8 million in
1999 compared to $10.7 million in 1998 due to our purchase of geothermal
steam field assets from Unocal Corporation on March 19, 1999.
Operating lease expenses increased by $16.5 million to $33.6 million
in 1999 compared to $17.1 million in 1998. Of the increase, $10.8 million
is due to the sale-leaseback in May 1999 of the 14 geothermal power plants
acquired from PG&E in May 1999 and the Sonoma Power Plant, which we
acquired in July 1998. We later added the Calistoga Power Plant, which we
acquired in October 1999, to that lease. The remainder of the increase is
primarily due to recording a full year of expense in 1999 versus a partial
year in 1998 for the Greenleaf 1 and 2 Power Plants, which were leased
commencing in August 1998.
Service contract expenses increased by $22.8 million to $40.2 million
in 1999 compared to $17.4 million in 1998 due to higher recorded purchases
of electricity and gas that were sold to third parties.
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Gross profit -- Gross profit increased by $108.9 million, or 62%, to $285.9
million in 1999 compared to $177.0 million in 1998 due primarily to the purchase
of geothermal steam field assets from Unocal Corporation on March 19, 1999 and
14 geothermal power plants from PG&E on May 7, 1999. Overall, the consolidated
geothermal operations at the Geysers increased gross profit in 1999 by $62.7
million compared to 1998. Also, contributing $12.4 million to the increase is
the Gilroy Power Plant, which benefited from the contract restructuring with
PG&E. The Pasadena Power Plant, which benefited from a full year of operations
in 1999, contributed an increase of $17.0 million, and we also realized $11.4
million in additional equity income from unconsolidated projects in 1999
compared to 1998 owing mostly to increased distributions from the Sumas Power
Plant.
Project development expenses -- Project development expenses increased by
$3.5 million, or 49%, in 1999 to $10.7 million compared to $7.2 million in 1998
due to the overall heavier pace in development activities as described in
"Business -- Project Development and Acquisitions."
General and administrative expenses -- In 1999 general and administrative
expenses were $48.7 million compared to $23.2 million in 1998. The increase of
110% or $25.5 million is largely attributable to the establishment of regional
offices in Pleasanton, CA, and Boston, MA, the build-up of our Houston, TX
regional office and the establishment of our construction management office in
Sacramento, CA. In addition to higher headcount and salaries associated with our
substantial growth, we incurred larger employee bonus expense owing to the
record year we experienced in 1999. The increased general and administrative
investment in 1999 reflects, in part, increased expenses designed to support our
growth in 2000 and beyond.
Interest expense -- Interest expense before capitalization of interest was
$138.5 million in 1999 compared to $93.7 million in 1998, an increase of $44.8
million due to higher debt balances in 1999 (total debt increased by $982.3
million due primarily to our public offering of $600.0 million of senior notes
on March 29, 1999). However, actual reported interest expense increased by a
much smaller $4.4 million, or 5%, in 1999 compared to 1998 because we
capitalized substantially more interest in 1999 compared to 1998 due to our
heavy power plant construction program. By the fourth quarter of 1999, we had
nine construction projects underway. We capitalized $47.3 million of interest
expense in 1999 compared to $7.0 million in 1998, which is an increase of $40.3
million in capitalized interest expense.
Total interest expense on senior notes increased by $46.1 million to $121.8
million in 1999 compared to $75.7 million in 1998. Although the average interest
rate on the senior notes decreased by 0.4% in 1999 compared to 1998, interest
expense increased because of the additional $600.0 million of senior notes
issued in March 1999. The proceeds of the senior notes issued in March of 1999
were used partially to retire $120.6 million of debt related to the Gilroy Power
Plant, and interest expense on the Gilroy debt decreased by $6.7 million in 1999
compared to 1998. Additionally, we increased debt by $97.8 million with the
acquisition of Sheridan Energy on October 1, 1999 and due to Sheridan's purchase
of certain gas reserves from Vintage Petroleum, Inc. on December 31, 1999.
Interest on Sheridan debt was $1.3 million in 1999. We also increased debt by
$239.4 million by acquiring CGCA on December 17, 1999. Interest expense from
CGCA debt in 1999 following the acquisition was $491,000.
Distributions on Trust Preferred Securities -- In October 1999 we completed
a public offering by a subsidiary trust of 5,520,000 HIGH TIDES. The accrued
distributions through December 31, 1999 were $2.6 million.
Interest income -- In 1999, interest income was $24.1 million compared to
$12.3 million in 1998. The increase of 96% or $11.8 million is attributable to
higher average cash balances in 1999 owing to the public offerings of senior
notes and common stock in March, 1999, and due to the public offerings of common
stock and HIGH TIDES in October 1999.
Other income, net -- In 1999, other income was $1.3 million compared to
$1.1 million in 1998. In 1999 we recorded $655,000 of income associated with an
investment in Cheng Power Systems, Inc. and $324,000 from the sale of excess
nitrous oxide ("NOX") credits by the Bethpage Power Plant.
Provision for income taxes -- The effective income tax rate was
approximately 39% in 1999 compared to approximately 37% in 1998. The rate
increase in 1999 is primarily attributable to a higher average state tax
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rate based on the mix of states in which we worked. In 1999 our provision for
federal and state income taxes totaled $62.0 million versus $27.1 million in
1998, an increase of $34.9 million, which is due primarily to higher taxable
income in 1999.
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, trust preferred
securities and equity, and proceeds from 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:
YEARS ENDED DECEMBER 31,
-------------------------------------
2000 1999 1998
----------- ----------- ---------
(IN THOUSANDS)
Beginning cash and cash equivalents.............. $ 349,371 $ 96,532 $ 48,513
Cash flows from:
Operating activities........................... 650,330 264,083 164,579
Investing activities........................... (3,554,159) (1,490,417) (400,003)
Financing activities........................... 3,143,156 1,479,173 283,443
----------- ----------- ---------
Net increase in cash and cash
equivalents.......................... 239,327 252,839 48,019
----------- ----------- ---------
Ending cash and cash equivalents................. $ 588,698 $ 349,371 $ 96,532
=========== =========== =========
Operating activities for 2000 provided $650.3 million, a 146% increase from
2000, consisting of approximately $141.6 million of depreciation and
amortization, $323.5 million of net income, $30.0 million of distributions from
unconsolidated investments in power projects, $62.6 million of deferred income
taxes and a $709.5 million net increase in operating liabilities. This was
partially offset by a $592.2 million net increase in operating assets and $24.6
million of income from unconsolidated investments. The increase in cash provided
from operating activities in 2000 is primarily due to higher net income derived
from our acquisition activity, favorable pricing, and increased production in
1999 and 2000.
Investing activities for 2000 used $3.6 billion, primarily due to $3.0
billion for construction costs and capital expenditures including gas
turbine-generator costs and associated capitalized interest, $840.9 million for
acquisitions (see Note 4 of the Notes to Consolidated Financial Statements for
further discussion), $141.1 million of advances to joint ventures, $53.1 million
of capitalized project development costs, including associated capitalized
interest, $184.5 million increase in notes receivables primarily due to our
Delta Energy Center development partner and our long-term Gilroy restructuring
receivables and $15.6 million increase in restricted cash related to certain
project financings. The increase in cash used in investing activities in 2000 is
primarily due to increased construction and acquisition activity compared to
1999.
Financing activities for 2000 provided $3.1 billion of cash consisting of
$1.0 billion proceeds from the issuance of our Senior Notes due 2005 and Senior
Notes due 2010, $2.2 billion in borrowings under various credit facilities and
$1.7 billion of proceeds from offerings of our common stock and HIGH TIDES. This
was offset by $1.7 billion of repayments on various credit facilities and $52.7
million of financing costs. The increase in cash provided from financing
activities in 2000 is primarily due to the debt and equity offerings issued
during 2000, as well as the HIGH TIDES offerings.
As discussed in Note 19 of the Notes to Consolidated Financial Statements
and under the caption "Item 1 -- Business -- Recent Developments", there is
considerable uncertainty surrounding the California power market. Regardless of
the resolution of the current situation, we do not believe that a possible
uncollectibility of remaining receivables from PG&E would have a material
adverse effect on our liquidity or cash flows. However, failure to collect a
significant portion of the receivables could have a materially adverse effect on
our Statement of Operations.
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,
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borrowings available under the lines of credit, access to the capital markets
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.
Credit Facilities (see Note 7 of the Notes to Consolidated Financial
Statements)
At December 31, 2000, we maintained a borrowing base in Canada of Cdn
$304.0 million (approximately US $202.7 million at December 31, 2000) under
three facilities. At December 31, 2000, we had US $144.5 million outstanding
under these facilities. The facilities bear interest at variable rates. The
weighted average rate for each of the facilities in 2000 was 8.52%.
Additionally, commitment fees of 0.25% accrue on any unused portion of these
facilities.
At December 31, 2000, we through our wholly owned subsidiary CNGC,
maintained a borrowing base of $99.1 million with Bank One, Texas N.A. under two
facilities. In August 2000, we repaid the outstanding balance of $93.3 million
and terminated the agreement. As of December 31, 1999, CNGC had total borrowings
of $97.8 million outstanding under this facility. The facility bore interest at
variable rates. At December 31, 1999, the interest rate was 8.6%. The lines of
credit were secured by CNGC's oil and gas properties.
At December 31, 2000, we had an amended and restated $400.0 million,
three-year revolving line of credit with a consortium of commercial lending
institutions with the Bank of Nova Scotia as agent, which replaced an existing
$100.0 million credit facility. A maximum of $200.0 million of the credit
facility may be allocated to letters of credit. At December 31, 2000, we had
$40.0 million in borrowings and $157.9 million of letters of credit outstanding
under the amended and restated credit facility. At December 31, 1999, we had no
borrowings and $28,800 in letters of credit outstanding under this credit
facility. The interest rate ranged from 7.88% to 9.75% during 2000.
Project Financing (see Note 8 of the Notes to Consolidated Financial
Statements)
In November 1999, we entered into a credit agreement for $1.0 billion
through our wholly owned subsidiary Calpine Construction Finance Company L.P.
with a consortium of banks with the lead arranger being The Bank of Nova Scotia
and the lead arranger syndication agent being Credit Suisse First Boston. The
non-recourse credit facility is utilized to finance the construction of the our
diversified portfolio of gas-fired power plants currently under development. We
currently intend to refinance this construction facility in the long-term
capital markets prior to its four-year maturity. As of December 31, 2000, we had
$544.8 million in borrowings outstanding under the facility. Borrowings under
this facility bear variable interest.
In October 2000, we entered into a credit agreement for $2.5 billion
through our wholly owned subsidiary Calpine Construction Finance Company II, LLC
with a consortium of banks with the lead arrangers being The Bank of Nova Scotia
and Credit Suisse First Boston. The non-recourse credit facility is utilized to
finance the construction of our diversified portfolio of gas-fired power plants
currently under development. We currently intend to refinance this construction
facility in the long-term capital markets prior to its four-year maturity. As of
December 31, 2000, we had $156.8 million in borrowings outstanding under the
facility. Borrowings under this facility bear variable interest.
As part of our acquisition of the Auburndale Power Plant, we assumed a
facility that provides for project financing loans aggregating $126.0 million.
Amounts outstanding under the facility bear variable interest. The weighted
average interest rate for this facility was 7.51% during 2000 and $121.5 million
was outstanding under the facility at December 31, 2000.
On December 17, 1999, we acquired 80% of the common stock of CGCA which
owns 100% of the Newark and Parlin Power Plants ("Newark & Parlin"). At December
31, 2000 there was $116.7 million outstanding on a fifteen year non-recourse
term loan which is a joint and severable liability of Newark & Parlin. The
interest rate on the outstanding principal is variable. As of December 31, 2000,
$116.7 million was outstanding under the facility. The weighted average interest
rate during 2000 was 7.68%.
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As part of our acquisition of SkyGen, we assumed a term loan for the Broad
River Energy Center and a steam injection addition loan, with the latter
expected to be converted to a term loan in 2001. Both the project loan and the
steam injection addition loan mature on March 1, 2007. The construction loans
require only variable interest payments through the conversion date, and blended
payments of principal and interest following conversion to a term loan. As of
December 31, 2000, $115.9 million was outstanding under the facilities. The
weighted average interest rate during 2000 was 8.02%.
As part of our acquisition of SkyGen, we entered into financing to
construct the Pine Bluff Energy Center. As part of the related credit agreement,
the lenders will provide a facility whereby the Company can borrow up to $142.0
million to fund construction. Of this amount, $32.0 million is secured by
guarantees or letters of credit from the members or their affiliates. Upon
completion of construction (the "Conversion Date"), equity contributions of
$32.0 million will be made to repay a portion of the construction loan and the
balance of the construction loan will be converted to a term loan. The term loan
will consist of three tranches: Tranche A in the amount of $30.0 million with a
maturity date of 8 1/2 years from the Conversion Date, Tranche B in the amount
of $45.0 million with a maturity date of 13 1/2 years from the Conversion Date,
and Tranche C in the amount of $35.0 million with a maturity date of 17 1/2
years from the Conversion Date. Interest on the construction loan is variable.
For 2000, the interest rate averaged 8.22%. As of December 31, 2000, we had
$113.2 million in outstanding borrowings.
As part of our acquisition of SkyGen, we have entered into an arrangement
with a syndicate of commercial banks to obtain financing to construct the Hog
Bayou Energy Center. As part of the related credit agreement, the lenders will
provide a facility to fund construction whereby we can borrow up to $38.0
million under an equity bridge loan and $104.6 million under a construction
loan. The equity bridge loan matures on December 31, 2001 and the construction
loan matures on December 31, 2002. As of December 31, 2000, we had borrowed
$38.0 million under the equity bridge loan and $70.0 million under the
construction loan. The facilities had a weighted average interest rate of 8.24%
during 2000.
As part of our acquisition of SkyGen, we entered into financing for the
construction of the RockGen Energy Center. As part of the related credit
agreement, the lender provided a facility whereby we can borrow up to $152.6
million to fund construction. Construction loans consist of a project loan of
$143.7 million and a steam injection addition loan of $8.9 million. Upon
completion of construction, the balance of the construction loans will be
converted to a term loan. The term loan consists of two tranches: Tranche A in
the amount of $143.7 million, and Tranche B in the amount of $8.9 million. Both
the project loan and the steam injection addition loan mature on March 1, 2007.
Interest on the construction loans is variable. As of December 31, 2000, we had
borrowings of $89.8 million. The weighted average interest rate during 2000 was
7.97%.
On December 17, 1999, we acquired 80% of the common stock of CGCA which
owns 100% of Morris LLC ("Morris"). In 1997, Morris entered into a construction
and term loan agreement to provide non-recourse project financing for a major
portion of the Morris Project. The agreement provides $85.6 million of 5 year
term loan commitments and $5.4 million in letter of credit commitments. As of
December 31, 2000, $85.6 million was outstanding as a term loan under the
agreement and no amounts were pledged under the letter of credit. Interest on
the term loan is variable. The weighted average interest rate during 2000 was
7.39%.
As part of our acquisition of SkyGen, we assumed a term loan for the DePere
Energy Center, which had a weighted average interest rate of 7.68% during 2000.
As of December 31, 2000, we had $47.2 million of outstanding borrowings.
In December 2000, we acquired the remaining interest in the Dighton Power
Plant. We assumed project financing for the plant. The weighted average interest
rate during 2000 was 7.79%. At December 31, 2000 we had $32.8 million of
outstanding borrowings.
In August 1996, we entered into an agreement with Banque Nationale de Paris
("BNP") to finance the acquisition of the Gilroy Power Plant. In April 1999, we
repaid the entire loan of $120.6 million to BNP with a portion of the net
proceeds from the offering of Senior Notes due 2006. We recorded an
extraordinary loss of
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$1.2 million after taxes as a result of the repayment for the write-off of
unamortized deferred financing cost associated with the BNP financing.
On January 4, 1999, we entered into a credit agreement with ING (U.S.)
Capital LLC ("ING") to provide up to $265.0 million of non-recourse project
financing for the construction of the Pasadena facility expansion. On August 31,
2000, we repaid the outstanding balance of $224.2 million under the credit
agreement.
Capital Markets Offerings (see Notes 9, 11 and 14 of the Notes to Consolidated
Financial Statements)
On February 10, 2000, we through our wholly-owned subsidiary, Calpine
Capital Trust II, a statutory business trust created under Delaware law,
completed a private offering of 7,200,000 HIGH TIDES at a value of $50.00 per
share. The gross proceeds from the offering were $360.0 million.
On August 9, 2000, we completed a public offering of 23,000,000 shares of
our common stock at $34.75 per share. The gross proceeds from the offering were
$799.3 million.
On August 10, 2000, we completed a public offering of $250.0 million of our
8 1/4% Senior Notes due 2005 and $750.0 million of our 8 5/8% Senior Notes due
2010. The 8 1/4% Senior Notes mature on August 15, 2005 and interest is payable
semi-annually. The 8 5/8% Senior Notes mature on August 15, 2010 and interest is
payable semi-annually. Both issuances of the Senior Notes may be redeemed at any
time prior to their respective stated maturity at a redemption price equal to
100% of the principal amount of the Senior Notes being redeemed plus accrued and
unpaid interest plus a make-whole premium.
On August 9, 2000, we through our wholly-owned subsidiary, Calpine Capital
Trust III, a statutory business trust created under Delaware law, completed a
private offering of 10,350,000 HIGH TIDES at a price of $50.00 per share. The
gross proceeds from the offering were $517.5 million. The net proceeds from the
private offering were used by our subsidiary to invest in our convertible
subordinated debentures, which represent substantially all of the subsidiary's
assets.
Debt Maturities
At December 31, 2000, 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. During 1998, we issued $400.0 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. During 1999, we issued
$350.0 million of 7 3/4% Senior Notes Due 2009, which mature on April 15, 2009,
with interest payable semi-annually on April 15 and October 15 of each year.
Also during 1999, we issued $250.0 million of our 7 5/8% Senior Notes Due 2006,
which mature on April 15, 2006, with interest payable semi-annually on April 15
and October 15.
The annual principal maturities of the borrowings under lines of credit,
project financings, notes payable, senior notes and capital lease obligations as
of December 31, 2000, are as follows (in thousands):
2001..................................................... $ 61,558
2002..................................................... 98,151
2003..................................................... 615,616
2004..................................................... 371,115
2005..................................................... 283,938
Thereafter............................................... 3,061,538
----------
Total.......................................... $4,491,916
==========
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OUTLOOK
Our strategy is to continue our rapid growth by capitalizing on the
significant opportunities in the power industry, 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 of new and expansion of existing power plants. We are
actively pursuing the development of new and expansion of both baseload
and peaking capacity at our existing 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.
We currently have twenty-five projects under construction, representing
an additional 14,028 megawatts of net capacity. Included in these
twenty-five projects is an expansion of our Broad River Energy Center,
which represents 360 megawatts. We have also announced plans to develop
twenty-eight additional power generation projects, representing a net
capacity of 15,142 megawatts. Included in these twenty-eight development
projects are seven expansion projects: Pine Bluff Energy Center, DePere
Energy Center, Auburndale and the California Peakers (which encompasses
expansions of the Gilroy Power Plant, the Watsonville Power Plant, the
Greenleaf 2 Power Plant and the King City Power Plant.) These expansion
projects represent 917 megawatts.
- Acquisition of power plants. Our strategy is to acquire power generating
facilities that meet our stringent acquisition criteria and 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 numerous acquisitions to date.
- 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 74 power plants with a net
capacity of 19,877 megawatts, after completion of our 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. We believe that achieving and
maintaining a low-cost of production will be increasingly important to
compete effectively in the power generation industry.
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, 2000, our total consolidated indebtedness was $4.5 billion, our total
consolidated assets were $9.7 billion and our stockholders' equity was $2.2
billion. 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,
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- 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 certain of our
existing debt agreements 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, the indentures governing our
senior notes may require us to make an offer to purchase our senior notes. We
cannot assure you that we will have the financial resources necessary to
purchase our senior notes in this event.
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 senior notes
and other debt and to enable us to comply with the terms of our indentures and
other debt agreements. If we are unable to comply with the terms of our
indentures and other 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 senior notes and other 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 indentures and
other debt agreements. If cash flow is insufficient and refinancing or
additional financing is unavailable, we may be forced to default on our senior
notes and other 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 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). As of December 31, 2000, our subsidiaries had $1.5 billion of
project financing. We intend to utilize project financing, when appropriate in
the future, and this financing will be effectively senior to our senior notes.
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 project financing that our subsidiaries may incur to finance the
acquisition and development of new power generation facilities.
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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, consisting of senior unsecured
indebtedness, project financing and lease obligations. Most of our current
construction costs are financed through one of our two Calpine Construction
Finance Company ("CCFC") non-recourse debt facilities (see Note 8 of the Notes
to Consolidated Financial Statements). As construction projects attain
commercial operation, we intend to refinance construction debt borrowings under
the CCFC facilities with corporate level long-term capital market financings. As
of December 31, 2000, we had approximately $4.5 billion of total consolidated
indebtedness, $1.5 billion of project financing, $210.9 million of capital lease
obligations, $2.6 billion in senior notes and $197.0 million of notes payable
and borrowings under lines of credit. Each 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
substantially reduce our revenue under such agreements.
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,
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- 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.
Our power generation facilities may not operate as planned. Upon completion
of our projects currently under construction, we will operate 69 of the 74 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. For calendar year 2000, our gas-fired and
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geothermal power generation facilities have operated at an average availability
of approximately 90% and 97%, respectively. 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 or power generated, 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.
The current issues in the California power market could adversely affect
our performance. As described within, the California power market is currently
in a state of disarray. Two of the three major utilities in California have been
widely reported to be facing the prospect of insolvency, including PG&E which is
one of our customers and which has defaulted on payments to us. State and
federal regulators and legislators, along with the major participants in the
market and consumer groups, are attempting to resolve this situation, but the
ultimate result of this effort is not yet known. We are actively involved in all
aspects of this regulatory, legislative and contractual effort. While we cannot
predict the outcome of this very fluid process, or the ultimate impact any such
outcome will have upon us, management believes that the resolution of this
problem will not have a material adverse effect on our results of operations or
financial condition.
We depend on our electricity and thermal energy customers. A majority of
our power generation facilities currently rely on one or more power sales
agreements with one or more utilities or other customers for all or
substantially all of such facility's revenue. In addition, sales of electricity
to two utility customers during 2000, PG&E and Texas Utilities Electric Company,
comprised approximately 27.4% and 8.1%, respectively, of our total revenue 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
F-27
63
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
reinterpreted, 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 PURPA, the Public Utility Holding Company Act of
1935, as amended, ("PUHCA"), and state and local regulations. PUHCA provides for
the extensive regulation of public utility holding companies and their
subsidiaries. PURPA provides 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 an Exempt Wholesale Generator
("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility
must be not more than 50% owned by one or more electric utility companies or
electric utility holding companies. 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. Generally, 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 FERC
regulations, a QF cannot be owned by an electric utility or electric utility
holding company. In addition, a loss of QF status could, depending on the
particular power purchase agreement, allow the power purchaser to cease taking
and paying for electricity or to seek refunds of past amounts paid and thus
could cause the loss of some or all contract revenues or otherwise impair the
value of a project. 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 "Item
1. -- Business -- Government Regulation -- Federal Energy Regulation -- Federal
Power Act 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
provide assurance that any legislation passed would not adversely affect our
existing domestic projects.
F-28
64
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 (which had discontinued the bulk of its operation as of February 1, 2001)
and an independent system operator, and for direct access to generation for all
power purchasers outside the power exchange under certain circumstances. See
"Item 1. -- Business -- Recent Developments -- California Power Market."
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, and we encounter competition
from utilities, industrial companies and other independent 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 that provide for direct
access for all customers as of April 1, 1998. In Texas, recently enacted
legislation phases-in a deregulated power market commencing January 1, 2001.
Regulatory initiatives are also being considered in other states, including New
York and states in New England. This competition has put pressure on electric
utilities to lower their costs, including the cost of purchased electricity, and
increasing competition in the supply of electricity in the future will increase
this pressure. See "Item 1. -- Business -- Recent Developments -- California
Power Market."
Our international investments may face uncertainties. We have an investment
in geothermal steam fields located in Mexico and investments in oil and natural
gas resources and power development projects in Canada and we 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, financial results and future growth.
Seismic disturbances could damage our projects. 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.
F-29
65
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,
- variations in levels of production, and
- seasonal variations in energy prices.
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, the power markets in which we
participate, 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 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
F-30
66
table summarizes the fair market value of our existing interest rate swap
agreements as of December 31, 2000 (dollars in thousands):
NOTIONAL WEIGHTED
PRINCIPAL AVERAGE FAIR
MATURITY DATE AMOUNT INTEREST RATE MARKET VALUE
------------- --------- ------------- ------------
2001............................................ $ 59,934 7.4% $ (501)
2007............................................ 38,150 8.0% (3,431)
2007............................................ 38,150 8.0% (3,414)
2007............................................ 30,708 7.9% (3,178)
2007............................................ 30,708 7.9% (3,161)
2009............................................ 15,000 6.9% (601)
2011............................................ 59,433 6.9% (2,491)
2012............................................ 121,464 6.5% (3,677)
2014............................................ 72,277 6.7% (2,608)
2015............................................ 22,500 7.0% (1,523)
2017............................................ 50,425 5.9% 868
2018............................................ 17,500 7.0% (1,427)
-------- --- --------
Total $556,249 7.0% $(25,144)
======== === ========
Short-term investments. As of December 31, 2000, we have short-term
investments of $149.2 million. These short-term investments consist of highly
liquid investments with maturities less than three months. 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.
Energy price fluctuations. We enter into derivative commodity instruments
to reduce our exposure to the impact of price fluctuations, primarily
electricity and natural gas prices. Such instruments include over-the-counter
financial swaps and physical options with major energy derivative product
specialists. All transactions are subject to our risk management policy which
does not permit speculative positions. Financial swaps are accounted for under
the hedge method of accounting. Current revenues and costs reflect the full
effect of price movement on physical options. Cash flows from derivative
instruments are recognized as incurred through changes in working capital.
The fair value gain (loss) of outstanding derivative commodity instruments
and the change in fair value that would be expected from a ten percent adverse
price change are shown in the table below (in thousands):
CHANGE IN FAIR
VALUE FROM
10% ADVERSE
FAIR VALUE PRICE CHANGE
---------- --------------
At December 31, 2000
Refined Products.......................................... $ (50) $ (35)
Electricity............................................... (2,937) (429)
Natural Gas............................................... 105,825 (71,964)
-------- --------
Total(1).......................................... $102,838 $(72,428)
======== ========
- ---------------
(1) Total includes the fair market value of the physical options of $1.2
million, excluded in Note 2 to the Consolidated Financial Statements.
All hedge positions offset physical positions exposed to the cash market.
None of the offsetting physical positions are included in the above table.
The fair value of over-the-counter instruments is estimated based on quoted
market prices of comparable contracts.
F-31
67
Price changes were calculated by assuming an across-the-board ten percent
adverse price change regardless of term or historical relationship between the
contract price of an instrument and the underlying commodity price. In the event
of an actual ten percent change in prompt month prices, the fair value of
Calpine's derivative portfolio would typically change less than that shown in
the table due to lower volatility in out-month prices.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS
In June 1999, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 137, "Accounting for
Derivative Instruments and Hedging Activities -- Deferral of the Effective Date
of FASB Statement No. 133 -- an Amendment of FASB Statement No. 133." The
Statement amends SFAS No. 133 to defer its effective date to all fiscal quarters
of all fiscal years beginning after June 15, 2000. In June 2000, the FASB issued
SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging
Activities -- An Amendment of FASB Statement No. 133." Calpine formally adopted
these accounting requirements on January 1, 2001. Calpine currently holds four
classes of derivative instruments that will be impacted by the new
pronouncements -- interest rate swaps, foreign currency swaps, commodity
financial instruments, and commodity contracts.
Upon adoption of SFAS No. 133, the fair values of derivative instruments
designated as hedges will be recorded on the balance sheet as an asset or
liability at their fair value. The difference between the carrying value of the
derivative and its fair value at the date of adoption shall be recorded as a
transition adjustment. In the case of the effective portion of a hedge, which
previously addressed the variable cash flow exposure of a transaction, a
transition adjustment will be recorded as a cumulative-effect-type adjustment to
accumulated Other Comprehensive Income ("OCI"). In the case of the ineffective
portion of a hedge, an adjustment will be calculated using the dollar offset
method and charged to income or expense on the Income Statement as the effect of
a change in accounting principle. The fair values of derivative instruments that
are not designated as effective hedges and that do not meet the normal purchase
or sale exception of SFAS No. 138 will be recorded on the balance sheet as an
asset or liability at fair value and an adjustment will be charged to income or
expense on the Income Statement as the effect of a change in accounting
principle.
At the end of each quarter, the changes in fair values of derivative
instruments designated as cash flow hedges will be recorded on the balance sheet
as an asset or liability. In the case of the effective portion of a hedge, an
adjustment will be recorded to OCI. In the case of the ineffective portion of a
hedge, an adjustment will be calculated using the dollar offset method and
charged to income or expense on the Income Statement. The changes in fair values
of derivative instruments that are not designated as effective hedges and that
do not meet the normal purchase or sale exception of SFAS No. 138 will be
recorded on the balance sheet as an asset or liability and an offset will be
charged to income or expense on the Income Statement.
At January 1, 2001, the FASB had not resolved Derivatives Implementation
Group ("DIG") Issue 14-3, dealing with a proposed electric industry normal
purchases and sales exception for capacity sales transactions. Calpine has
assumed that the FASB will permit the use of this exception for capacity sales
contracts that include all of the following characteristics:
- It is probable at inception and throughout the term of the individual
contract that the contract -- if exercised by the holder -- will not
settle net, as defined in SFAS No. 133, and will result in physical
delivery.
- The electricity contract would not otherwise be considered an energy
trading contract under the Emerging Issues Task Force Issue No. 98-10.
- The contract meets all other applicable criteria outlined in paragraph
10(b) of SFAS No. 133.
All capacity sales contracts and other commodity contracts currently held
by Calpine meet the above criteria and are therefore subject to the FASB's final
decision which is expected in early 2001. Pending the FASB's final decision,
Calpine assumes that these contracts will be exempt from derivative accounting
treatment under the normal purchases and sales exemption. See Note 2 of the
Notes to Consolidated Financial Statements for the financial statement effects
if Calpine had adopted SFAS No. 133 on December 31, 2000.
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68
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors
and Stockholders of Calpine Corporation:
We have audited the accompanying consolidated balance sheets of Calpine
Corporation (a Delaware corporation) and subsidiaries as of December 31, 2000
and 1999, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2000. 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 conducted our audits in accordance with auditing standards generally
accepted in the United States. 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 provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Calpine Corporation and
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
San Jose, California
March 14, 2001
F-33
69
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 1999
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
2000 1999
---------- ----------
Current assets:
Cash and cash equivalents................................. $ 588,698 $ 349,371
Accounts receivable, net of allowance of $11,078 and
$3,343.................................................. 649,422 127,485
Inventories............................................... 36,883 16,417
Prepaid expenses.......................................... 27,515 24,848
Other current assets...................................... 41,165 8,287
---------- ----------
Total current assets............................... 1,343,683 526,408
---------- ----------
Property, plant and equipment, net.......................... 7,459,055 2,908,056
Investments in power projects............................... 205,621 243,225
Project development costs................................... 38,597 24,018
Notes receivable............................................ 217,927 23,548
Restricted cash............................................. 88,618 43,615
Deferred financing costs.................................... 139,631 54,215
Other assets................................................ 244,125 168,521
---------- ----------
Total assets....................................... $9,737,257 $3,991,606
========== ==========
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and borrowings under lines of credit,
current portion......................................... $ 1,087 $ 38,867
Accounts payable.......................................... 765,613 84,353
Project financing, current portion........................ 58,486 8,603
Capital lease obligation, current portion................. 1,985 --
Income taxes payable...................................... 63,409 8,835
Accrued payroll and related expenses...................... 53,667 24,345
Accrued interest payable.................................. 75,865 37,058
Other current liabilities................................. 149,080 73,250
---------- ----------
Total current liabilities.......................... 1,169,192 275,311
---------- ----------
Notes payable and borrowings under lines of credit, net of
current portion........................................... 195,862 97,303
Project financing, net of current portion................... 1,473,869 357,137
Senior notes................................................ 2,551,750 1,551,750
Capital lease obligation, net of current portion............ 208,876 --
Deferred income taxes, net.................................. 567,292 291,458
Deferred lease incentive.................................... 60,676 64,245
Deferred revenue............................................ 92,511 33,876
Other liabilities........................................... 20,389 23,476
---------- ----------
Total liabilities.................................. 6,340,417 2,694,556
---------- ----------
Commitments and contingencies (see Note 18)
Company-obligated mandatorily redeemable convertible
preferred securities of subsidiary trusts................. 1,122,490 270,713
Minority interests.......................................... 37,576 61,705
---------- ----------
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized
10,000,000 shares; none issued and outstanding in 2000
and 1999................................................ -- --
Common stock, $.001 par value per share; authorized
500,000,000 shares in 2000 and 400,000,000 in 1999;
issued and outstanding 283,715,058 shares in 2000 and
252,215,680 shares in 1999.............................. 284 252
Additional paid-in capital................................ 1,700,505 751,215
Retained earnings......................................... 536,617 213,165
Accumulated other comprehensive loss...................... (632) --
---------- ----------
Total stockholders' equity......................... 2,236,774 964,632
---------- ----------
Total liabilities and stockholders' equity......... $9,737,257 $3,991,606
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-34
70
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
2000 1999 1998
---------- -------- --------
Revenue:
Electricity and steam sales............................. $1,702,320 $760,325 $507,897
Service contract revenue................................ 480,234 43,773 20,249
Income from unconsolidated investments in power
projects............................................. 24,639 36,593 25,240
Interest income on loans to power projects.............. 4,827 1,226 2,562
Other revenue........................................... 70,773 5,818 --
---------- -------- --------
Total revenue................................... 2,282,793 847,735 555,948
---------- -------- --------
Cost of revenue:
Fuel expenses........................................... 612,947 268,734 181,593
Plant operating expenses................................ 220,222 122,707 78,085
Depreciation expense.................................... 154,263 82,812 73,988
Production royalties.................................... 32,325 13,767 10,714
Operating lease expenses................................ 69,419 33,594 17,129
Service contract expenses............................... 469,500 40,236 17,417
---------- -------- --------
Total cost of revenue........................... 1,558,676 561,850 378,926
---------- -------- --------
Gross profit......................................... 724,117 285,885 177,022
Project development expenses.............................. 27,556 10,712 7,165
General and administrative expenses....................... 94,113 48,671 23,181
---------- -------- --------
Income from operations............................... 602,448 226,502 146,676
Interest expense.......................................... 56,700 91,162 86,726
Distributions on trust preferred securities............... 44,210 2,565 --
Interest income........................................... (39,901) (24,106) (12,348)
Minority interest, net.................................... 2,684 -- --
Other income.............................................. (4,883) (1,335) (1,075)
---------- -------- --------
Income before provision for income taxes............. 543,638 158,216 73,373
Provision for income taxes................................ 218,951 61,973 27,054
---------- -------- --------
Income before extraordinary charge................... 324,687 96,243 46,319
Extraordinary charge net of tax benefit of $796, $793 and
$441.................................................... 1,235 1,150 641
---------- -------- --------
Net income........................................... $ 323,452 $ 95,093 $ 45,678
========== ======== ========
Basic earnings per common share:
Weighted average shares of common stock outstanding..... 264,799 209,314 160,969
Income before extraordinary charge...................... $ 1.23 $ 0.46 $ 0.29
Extraordinary charge.................................... $ (0.01) $ (0.01) $ (0.01)
Net income.............................................. $ 1.22 $ 0.45 $ 0.28
Diluted earnings per common share:
Weighted average shares of common stock outstanding
before dilutive effect of certain trust preferred
securities........................................... 280,776 222,644 169,311
Income before extraordinary charge and dilutive effect
of certain trust preferred securities................ $ 1.16 $ 0.43 $ 0.27
Dilutive effect of certain trust preferred
securities(1)........................................ $ (0.05) $ -- $ --
Income before extraordinary charge...................... $ 1.11 $ 0.43 $ 0.27
Extraordinary charge.................................... $ (0.01) $ -- $ --
Net income.............................................. $ 1.10 $ 0.43 $ 0.27
- ---------------
(1) Includes the effect of the assumed conversion of certain trust preferred
securities. For the twelve months ended December 31, 2000, the assumed
conversion calculation adds 31,746 shares of common stock and $20,841 to the
net income results, representing the after tax distribution expense on
certain trust preferred securities avoided upon conversion.
The accompanying notes are an integral part of these consolidated financial
statements.
F-35
71
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
ACCUMULATED
ADDITIONAL OTHER TOTAL
COMMON PAID-IN RETAINED COMPREHENSIVE STOCKHOLDERS' COMPREHENSIVE
STOCK CAPITAL EARNINGS LOSS EQUITY INCOME (LOSS)
------ ---------- -------- ------------- ------------- -------------
Balance, December 31,
1997...................... $160 $ 167,402 $ 72,394 $ -- $ 239,956
Issuance of 807,008 shares
of common stock, net of
issuance costs......... 1 1,109 -- -- 1,110
Tax benefit from stock
options exercised and
other.................. -- 222 -- -- 222
Comprehensive Income:
Net income................ -- -- 45,678 -- 45,678 $ 45,678
Other comprehensive
income................. -- -- -- -- -- --
--------
Total comprehensive
income................. -- -- -- -- -- $ 45,678
---- ---------- -------- ----- ---------- ========
Balance, December 31,
1998...................... 161 168,733 118,072 -- 286,966
---- ---------- -------- ----- ----------
Issuance of 90,923,032
shares of common stock,
net of issuance
costs.................. 91 576,505 -- -- 576,596
Tax benefit from stock
options exercised and
other.................. -- 5,977 -- -- 5,977
Comprehensive Income:
Net income................ -- -- 95,093 -- 95,093 $ 95,093
Other comprehensive
income................. -- -- -- -- -- --
--------
Total comprehensive
income................. -- -- -- -- -- $ 95,093
---- ---------- -------- ----- ---------- ========
Balance, December 31,
1999...................... 252 751,215 213,165 -- 964,632
---- ---------- -------- ----- ----------
Issuance of 27,997,846
shares of common stock,
net of issuance
costs.................. 28 782,068 -- -- 782,096
Issuance of 3,501,532
shares of common stock
for acquisitions....... 4 120,591 -- -- 120,595
Tax benefit from stock
options exercised and
other.................. -- 46,631 -- -- 46,631
Comprehensive Income:
Net income................ -- -- 323,452 -- 323,452 $323,452
Currency translation
adjustment............. -- -- -- (632) (632) (632)
--------
Total comprehensive
income................. -- -- -- -- -- $322,820
---- ---------- -------- ----- ---------- ========
Balance, December 31,
2000...................... $284 $1,700,505 $536,617 $(632) $2,236,774
==== ========== ======== ===== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-36
72
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN THOUSANDS)
2000 1999 1998
----------- ----------- ---------
Cash flows from operating activities:
Net income................................................ $ 323,452 $ 95,093 $ 45,678
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization........................... 141,594 87,210 74,285
Deferred income taxes, net.............................. 62,623 47,944 13,554
Income from unconsolidated investments in power
projects.............................................. (24,639) (36,593) (25,240)
Distributions from unconsolidated power projects........ 29,979 43,318 27,717
Loss on sale of assets.................................. -- 1,058 --
Change in operating assets and liabilities, net of
effects of acquisitions:
Accounts receivable................................... (477,126) (17,258) 10,172
Notes receivable...................................... (46,066) (13,919) --
Other current assets.................................. (25,324) (8,555) 24,012
Other assets.......................................... (43,654) (9,153) (28,968)
Accounts payable and accrued expenses................. 662,635 74,867 17,484
Other liabilities..................................... 46,856 71 5,885
----------- ----------- ---------
Net cash provided by operating activities.......... 650,330 264,083 164,579
----------- ----------- ---------
Cash flows from investing activities:
Purchases of property, plant and equipment................ (2,967,495) (946,701) (101,039)
Proceeds from sale and leaseback of plant................. 642,205 71,236 559
Acquisitions, net of cash acquired........................ (840,928) (540,587) (305,263)
Advances to joint ventures................................ (141,106) (48,066) (2,952)
Decrease (increase) in notes receivable................... (184,535) 1,270 18,967
Maturities of collateral securities....................... 6,445 1,850 6,030
Project development costs................................. (53,129) (30,635) (17,435)
Decrease (increase) in restricted cash.................... (15,616) 1,216 1,130
----------- ----------- ---------
Net cash used in investing activities.............. (3,554,159) (1,490,417) (400,003)
----------- ----------- ---------
Cash flows from financing activities:
Borrowings from project financing......................... 1,183,603 155,760 57,874
Repayments of project financing........................... (580,111) (123,386) (162,145)
Proceeds from notes payable and borrowings under lines of
credit.................................................. 1,051,225 163,675 --
Repayments of notes payable and borrowings under lines of
credit.................................................. (1,117,946) (129,721) --
Proceeds from issuance of Senior Notes.................... 1,000,000 600,000 400,000
Repurchase of Senior Notes................................ -- -- (8,250)
Proceeds from Company-obligated mandatorily convertible
preferred securities of a subsidiary trust.............. 877,500 276,000 --
Proceeds from equity offerings, net of issuance costs..... 773,249 597,368 --
Proceeds from issuance of common stock.................... 10,935 2,939 1,110
Write-off of deferred financing costs..................... 2,031 1,943 --
Financing costs........................................... (52,725) (65,405) (5,146)
Other..................................................... (4,605) -- --
----------- ----------- ---------
Net cash provided by financing activities.......... 3,143,156 1,479,173 283,443
----------- ----------- ---------
Net increase in cash and cash equivalents................... 239,327 252,839 48,019
Cash and cash equivalents, beginning of year................ 349,371 96,532 48,513
----------- ----------- ---------
Cash and cash equivalents, end of year...................... $ 588,698 $ 349,371 $ 96,532
=========== =========== =========
Cash paid during the year for:
Interest.................................................. $ 224,866 $ 117,376 $ 71,971
Income taxes.............................................. $ 142,659 $ 16,116 $ 2,167
The accompanying notes are an integral part of these consolidated financial
statements.
F-37
73
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") is engaged in the generation of electricity in the
United States and Canada. In pursuing this single business strategy, the Company
is involved in the development, acquisition, ownership and operation of power
generation facilities and the sale of electricity and its by-product, thermal
energy, primarily in the form of steam. The Company has ownership interests in
and operates gas-fired cogeneration facilities, gas fields, gathering systems
and gas pipelines, geothermal steam fields and geothermal power generation
facilities in the United States and Canada. 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.
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. In the case of the Company's interest in the Lost Pines
I project, the proportionate consolidation method is used. 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 6). All significant intercompany accounts and
transactions are eliminated in consolidation. Prior to the Company's acquisition
of Unocal's interest in its Geysers geothermal properties on March 19, 1999, the
Company used the proportionate consolidation method to account for Thermal Power
Company's ("TPC's") 25% ownership 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 in the United States 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 useful lives of the generation facilities (see Note 3).
Fair Value of Financial Instruments -- The carrying value of accounts
receivable, marketable securities, accounts and other payables approximate their
respective fair values due to their short maturities. See Note 9 for disclosures
regarding the fair value of the Senior Notes.
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 estimated to be used within one year is
determined using the specific identification method. For the remaining supplies
and spare parts, cost is generally determined using the weighted average cost
method.
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 commencement of construction, these
costs are transferred to construction in progress in property, plant and
equipment, net. Upon the start-up of plant operations, these costs are generally
transferred to property, plant
F-38
74
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
and equipment and amortized over the estimated useful life of the project.
Capitalized project costs are charged to expense if the Company determines that
the project is impaired.
Restricted Cash -- The Company is required to maintain cash balances that
are restricted by provisions of certain 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. 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 -- The deferred financing costs related to the
Company's Senior Notes are amortized over the life of the related debt, ranging
from 5 to 10 years using the effective interest rate method (See Note 9). The
deferred financing costs associated with the two Calpine Construction Finance
Company facilities are amortized over the 4-year facility lives using the
straight-line method (See Note 8). Costs incurred in connection with obtaining
other financing are deferred and amortized over the remaining life of the
related debt, generally ranging from 1 to 20 years.
Long-Lived Assets -- In accordance with Financial Accounting Standards
Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of," the Company evaluates the impairment of long-lived assets,
including goodwill, based on the projection of undiscounted cash flows whenever
events or changes in circumstances indicate that the carrying amounts of such
assets may not be recoverable. In the event such cash flows are not expected to
be sufficient to recover the recorded value of the assets, the assets are
written down to their estimated fair values.
Major Maintenance -- For major gas turbine generator refurbishments, the
Company defers the costs and amortizes them over 3 to 6 years. Geothermal steam
turbine refurbishments are expensed as incurred. These two methods are the
Company's primary accounting methods for major maintenance. Additionally, the
Company accrues in advance for certain non-annual planned maintenance.
Trust Preferred Securities -- During 1999 and 2000, the Company issued
trust preferred securities, which are treated as a minority interest in the
balance sheet and reflected as "Company-obligated mandatorily redeemable
convertible preferred securities of subsidiary trusts." The distributions are
reflected on the income statement as "distributions on trust preferred
securities." Financing costs related to these issuances are netted with the
principal amounts and are accreted over the securities' 30-year maturity by the
straight-line method (See Note 11).
Revenue Recognition -- The Company is first and foremost an electric
generation company, operating a portfolio of mostly wholly-owned plants but also
some plants in which its ownership interest is 50% or less and which are
accounted for under the equity method. In conjunction with its electric
generation business, the Company also produces, as a by-product, thermal energy
for sale to customers, principally steam hosts at its cogeneration sites. In
addition the Company acquires and produces natural gas for its own consumption
and sells the balance and small amounts of oil to third parties. To protect and
enhance the profit potential of its electric generation plants, the Company's
Calpine Energy Services, LP ("CES") subsidiary enters into electric and gas
hedging, balancing and related transactions in which purchased electricity and
gas is resold to third parties. CES acts as a principal, takes title to the
commodities purchased for resale and assumes the risks and rewards of ownership,
and therefore, in accordance with Staff Accounting Bulletin No. 101 and the
Emerging Issues Task Force ("EITF") Issue No. 99-19, CES recognizes revenue on a
gross basis, except in the case of qualifying hedge transactions, in which case
the net gain or loss from the hedging instrument is recorded in income against
the underlying hedged item when the effects of the hedged item are recognized.
F-39
75
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Hedged items typically included sales to third parties of natural gas produced,
purchases of natural gas to fuel power plants, and sales of generated
electricity. Finally, the Company, through Power Systems Mfg., LLC ("PSM"),
designs and manufactures spare parts for gas turbines and also generates small
amounts of revenue from occasional loans to power projects and by providing
operation and maintenance services to unconsolidated power plants. Further
details of the Company's revenue recognition policy for each type of revenue
transaction is provided below:
Electricity and Steam Sales -- Electrical energy revenue is recognized
upon transmission to the customer, and capacity and ancillary revenue is
recognized when contractually earned. In accordance with EITF Issue No. 91-6,
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 Calpine Geysers Company ("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,
2000, 1999 and 1998 would have been approximately $8.1 million lower, $24.2
million higher and $4.7 million lower, respectively. Net gains or losses from
qualified hedges of electricity positions are included in electricity and steam
sales.
Calpine Gilroy Cogen, LP ("Gilroy") had a long-term power purchase
agreement ("PPA") with Pacific Gas and Electric Company ("PG&E") for the sale of
energy through 2018. The terms of the PPA provided for 120 megawatts of firm
capacity and up to 10 megawatts of as-delivered capacity. On December 2, 1999,
the California Public Utilities Commission approved the restructuring of the PPA
between Gilroy and PG&E. Under the terms of the restructuring, PG&E and Gilroy
are each released from performance under the PPA effective November 1, 2002.
Under the restructured contract, in addition to the normal capacity revenue for
the period, Gilroy will earn from September 1999 to October 2002 restructured
capacity revenue it would have earned over the November 2002 through March 2018
time period, for which PG&E issues notes to the Company. At December 31, 2000,
Gilroy had $62.3 million of such notes receivable from PG&E. These notes will be
paid by PG&E during February 2003 to September 2014 (See Notes 15 and 19 for
further discussion).
Service Contract Revenue -- The Company recognizes revenue from power
and gas hedging, balancing and related activities through its wholly owned
subsidiary, CES. Revenue generated from CES through sales of purchased power and
purchased gas to third parties is recorded as service contract revenue when
delivery occurs or a position is settled.
The Company also performs operations and maintenance services for some
of the projects in which it has an interest. Revenue from investees is
recognized as service contract revenue on these contracts when the services are
performed.
Income from Unconsolidated Investments in Power Projects -- The Company
uses the equity method to recognize as revenue its pro rata share of the net
income or loss of the unconsolidated investment until such time, if applicable,
as the Company's investment is reduced to zero, at which time equity income is
generally recognized only upon receipt of cash distributions from the investee.
Interest Income on Loans to Power Projects -- The Company recognizes as
revenue interest income on loans to power projects in which it invests as the
interest is earned and realizable.
Other Revenues -- Revenue from the sale of crude oil is recognized upon
the passage of title, net of royalties and net of gains or losses from qualified
hedges. Revenue from natural gas production is recognized using the sales
method, net of royalties and net of gains or losses from qualified hedges.
The Company recognizes revenue from its PSM subsidiary as products are
delivered to the customer for smaller orders and on the Percentage of Completion
method for certain special large orders under which work is performed over an
extended time period.
F-40
76
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Concentrations of Credit Risk -- Financial instruments which potentially
subject the Company to concentrations of credit risk consist primarily of cash,
accounts receivable and notes receivable. The Company's cash accounts are
generally held in FDIC insured banks. The Company's accounts and notes
receivable are concentrated within entities engaged in the energy industry,
mainly within the United States (see Note 15). 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. 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. Cash flows from swap contracts accounted for as hedges
are classified in the same category as the item being hedged.
Energy Marketing Operations -- The Company, through its wholly owned
subsidiary CES, markets energy services to utilities, wholesalers, and end
users. CES provides these services by entering into contracts to purchase or
supply electricity and natural gas, primarily, at specified delivery points and
specified future dates. In some cases, CES utilizes financial instruments to
manage its exposure to electricity and natural gas price fluctuations, and to a
lesser degree, price fluctuations of oil and refined products. On December 31,
2000, CES held swap contracts with several entities in order to hedge these
price fluctuations.
At December 31, 2000, the Company had positions with a net fair value of
$104.0 million to protect the Company against the risks of fluctuating market
prices. The Company actively manages its positions, and it is the Company's
policy to not have any speculative positions. Net gains and losses related to
commodity swap contracts are recognized when realized. The Company's credit risk
associated with power and fuel 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
counterparties.
New Accounting Pronouncements -- In June 1999, the FASB issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities -- Deferral
of the Effective Date of FASB Statement No. 133 -- an Amendment of FASB
Statement No. 133." The Statement amends SFAS No. 133 to defer its effective
date to all fiscal quarters of all fiscal years beginning after June 15, 2000.
In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities -- An Amendment of FASB Statement No.
133." The Company formally adopted these accounting requirements on January 1,
2001. The Company currently holds four classes of derivative instruments that
will be impacted by the new pronouncements -- interest rate swaps, foreign
currency swaps, commodity financial instruments, and commodity contracts.
Upon adoption of SFAS No. 133, the fair values of derivative instruments
designated as hedges will be recorded on the balance sheet as an asset or
liability at their fair value. The difference between the carrying value of the
derivative and its fair value at the date of adoption shall be recorded as a
transition adjustment. In the case of the effective portion of a hedge, which
previously addressed the variable cash flow exposure of a transaction, a
transition adjustment will be recorded as a cumulative-effect-type adjustment to
accumulated Other Comprehensive Income ("OCI"). In the case of the ineffective
portion of a hedge, an adjustment will be calculated using the dollar offset
method and charged to income or expense on the Income Statement as
F-41
77
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
the effect of a change in accounting principle. The fair values of derivative
instruments that are not designated as effective hedges and that do not meet the
normal purchase or sale exception of SFAS No. 138 will be recorded on the
balance sheet as an asset or liability at fair value and an adjustment will be
charged to income or expense on the Income Statement as the effect of a change
in accounting principle.
At the end of each quarter, the changes in fair values of derivative
instruments designated as cash flow hedges will be recorded on the balance sheet
as an asset or liability. In the case of the effective portion of a hedge, an
adjustment will be recorded to OCI. In the case of the ineffective portion of a
hedge, an adjustment will be calculated using the dollar offset method and
charged to income or expense on the Income Statement. The changes in fair values
of derivative instruments that are not designated as effective hedges and that
do not meet the normal purchase or sale exception of SFAS No. 138 will be
recorded on the balance sheet as an asset or liability and an offset will be
charged to income or expense on the Income Statement."
At January 1, 2001, the FASB had not resolved Derivatives Implementation
Group ("DIG") Issue 14-3, dealing with a proposed electric industry normal
purchases and sales exception for capacity sales transactions. The Company has
assumed that the FASB will permit the use of this exception for capacity sales
contracts that include all of the following characteristics:
- It is probable at inception and throughout the term of the individual
contract that the contract -- if exercised by the holder -- will not
settle net, as defined in SFAS No. 133, and will result in physical
delivery.
- The electricity contract would not otherwise be considered an energy
trading contract under the EITF Issue No. 98-10.
- The contract meets all other applicable criteria outlined in paragraph
10(b) of SFAS No. 133.
All capacity sales contracts and other commodity contracts currently held
by the Company meet the above criteria and are therefore subject to the FASB's
final decision which is expected in early 2001. Pending the FASB's final
decision, the Company assumes that these contracts will be exempt from
derivative accounting treatment under the normal purchases and sales exemption.
Had the Company not made this assumption, total assets would have increased by
$9.6 million, total liabilities would have increased by $8.5 million and net
income would have increased by $1.1 million. The effect on the income statement
would be reported as a cumulative effect of change in accounting principle. The
table below reflects the amounts (in thousands), by derivative instrument that
would be recorded as assets, liabilities, expense, and OCI if the Company
adopted SFAS No. 133 on December 31, 2000.
INTEREST COMMODITY
RATE FINANCIAL
SWAPS INSTRUMENTS
-------- -----------
Current Derivative Asset.................................... $ -- $704,218
Long-Term Derivative Asset.................................. 868 120,206
-------- --------
Total Assets................................................ $ 868 $824,424
======== ========
Current Derivative Liability................................ 501 669,428
Long-Term Derivative Liability.............................. 25,510 68,420
Deferred Tax Liability...................................... (9,856) 33,938
-------- --------
Total Liabilities........................................... $ 16,155 $771,786
======== ========
Other Comprehensive Income.................................. $(15,287) $ 52,638
Reclassifications -- Certain prior years' amounts in the Consolidated
Financial Statements have been reclassified to conform to the 2000 presentation.
F-42
78
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
3. PROPERTY, PLANT AND EQUIPMENT, NET, AND CAPITALIZED INTEREST
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.
Proceeds from the sale of geothermal properties are applied against capitalized
costs, with no gain or loss recognized.
Geothermal costs, including an estimate of future costs to be incurred,
costs to optimize the productivity of the assets, 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 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 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,
exclusive of the estimated salvage value, typically 10%. The value of the
above-market or below-market pricing provided in power sales agreements and fuel
supply contracts acquired is recorded in property, plant and equipment, net and
is amortized over the above-market or below-market pricing period in the power
sales agreement or fuel supply contract with lives ranging from month-to-month
to 28 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.
The Company follows the successful efforts method of accounting for oil and
natural gas operations. Under the successful efforts method, capitalized costs
relating to proved properties are amortized using the units-of-production method
based on estimated proven reserves. The cost of unsuccessful exploration wells
is charged to operations.
As of December 31, 2000 and 1999, the components of property, plant and
equipment, net are as follows (in thousands):
2000 1999
---------- ----------
Geothermal properties....................................... $ 334,585 $ 366,059
Oil and gas properties...................................... 625,178 214,794
Buildings, machinery and equipment.......................... 1,927,803 1,215,063
Power sales agreements...................................... 159,337 145,957
Gas contracts............................................... 132,748 122,593
Other....................................................... 178,861 78,735
---------- ----------
3,358,512 2,143,201
Less: accumulated depreciation and amortization............. (328,461) (227,059)
---------- ----------
3,030,051 1,916,142
Land........................................................ 12,578 3,419
Construction in progress.................................... 4,416,426 988,495
---------- ----------
Property, plant and equipment, net.......................... $7,459,055 $2,908,056
========== ==========
F-43
79
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Construction in progress is primarily attributable to gas-fired projects
under construction. Upon commencement of plant operations, these costs are
transferred to Buildings, Machinery and Equipment.
Capitalized Interest -- The Company capitalizes interest on capital
invested in projects during the advanced stages of development and the
construction period. For the years ended December 31, 2000 and 1999, the Company
recorded net interest expense of $56.7 million and $91.2 million, respectively,
after capitalizing $171.0 million and $39.7 million of interest on general
corporate funds used for construction in 2000 and 1999, respectively, and after
$36.0 million and $7.6 million of interest capitalized on funds borrowed for
specific construction projects in 2000 and 1999, respectively. Upon commencement
of plant operations, capitalized interest is amortized over the estimated useful
life of the plant. The increase in the amount of interest capitalized during the
year ended December 31, 2000 reflects the significant increase in the Company's
power plant construction program.
4. ACQUISITIONS
The following acquisitions were consummated during the year ended December
31, 1999. All business combinations made during 1999 were accounted for as
purchases.
Unocal Transaction
On March 19, 1999, the Company acquired Unocal Corporation's Geysers
geothermal steam fields in northern California for approximately $102.2 million.
The steam fields fuel the Company's power plants located at the Geysers,
California. See below.
PG&E Transactions
On May 7, 1999, the Company completed the acquisition of 12 Sonoma County
and 2 Lake County power plants, located at the Geysers, California from PG&E for
approximately $212.8 million. These plants have a combined capacity of
approximately 657 megawatts of electricity.
Aidlin Transaction
On August 31, 1999, the Company completed the acquisition of an additional
50% interest in the Aidlin Power Plant from Edison Mission Energy and General
Electric Capital Corporation for a total purchase price of $7.2 million. The
Company previously owned a 5% interest in the project.
Calistoga and Silverado Transactions
On October 19, 1999, the Company purchased the Calistoga Power Plant, the
Silverado steam fields and related assets from FPL Energy and Caithness
Corporation for $77.9 million.
Calpine Natural Gas Company Transaction
On October 1, 1999, the Company completed the acquisition of Sheridan
Energy Inc. ("Sheridan"), a natural gas exploration and production company,
through a $38.8 million cash tender offer. The Company purchased the outstanding
shares of Sheridan's common stock for $5.50 per share. In addition, the Company
redeemed $11.9 million of outstanding preferred stock of Sheridan. Sheridan's
oil and gas properties are primarily located in Northern California and the Gulf
Coast region. Previously, the Company had acquired a 20% interest in Sheridan
California Energy, Inc. from Sheridan for $14.9 million. As a result of the two
aforementioned acquisitions, the Company now owns all of the assets of Sheridan
and included the results in its Consolidated Financial Statements at December
31, 1999. The Company subsequently renamed Sheridan as Calpine Natural Gas
Company ("CNGC"). The Company accounted for its investment in Sheridan under
F-44
80
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
the equity method until October 1, 1999. From October 1, 1999 through December
31, 1999, the results of CNGC's operations are consolidated.
Cogeneration Corporation of America Transaction
On December 17, 1999, the Company completed the acquisition of 80% of the
common stock of Cogeneration Corporation of America, Inc. ("CGCA") for
approximately $137.3 million with the remaining 20% being owned by NRG Energy
Inc., a subsidiary of Xcel Energy, Inc. As a result of this acquisition the
Company received an ownership interest in six natural gas-fired facilities
totaling approximately 461 megawatts of capacity and has assumed operations of
five of the plants.
Vintage Transaction
On December 31, 1999, but effective as of November 1, 1999, the Company
acquired proven natural gas reserves and certain leasehold acreage from Vintage
Petroleum, Inc. ("Vintage") of Tulsa, Oklahoma for approximately $71.5 million.
The Company added the remaining 58.8% working interest in the Rio Vista Gas Unit
and certain development acreage to its northern California gas portfolio. This
new production utilizes the Company's Sacramento Basin gas pipeline system. The
Company initially acquired a 40.7% working interest in the Rio Vista Gas Unit in
October 1999 through its Sheridan acquisition.
The following acquisitions were consummated during the year ended December
31, 2000. All business combinations made during 2000 were accounted for as
purchases.
Western Transaction
On February 4, 2000, the Company acquired 100% of the stock of Western Gas
Resources California ("Western") from Western Gas Resources, Inc. for $14.9
million. Western's assets include the 130-mile Steelhead natural gas pipeline
and the remaining interest in the Sacramento River Gas System natural gas
pipeline, now 100% owned by Calpine.
Hidalgo Transaction
On March 30, 2000, the Company purchased a 78.5% interest in the 502
megawatt Hidalgo Energy Center which was under construction in Edinburg, Texas,
from Duke Energy North America for $235 million. The purchase included a cash
payment of $134 million and the assumption of a $101 million capital lease
obligation. The Hidalgo Energy Center sells power into the Electric Reliability
Council of Texas' ("ERCOT") wholesale market. Construction of the facility began
in February 1999, and commercial operation was achieved in June 2000.
KIAC and Stony Brook Transaction
On May 31, 2000, Calpine acquired the remaining 50% interests in the 105
megawatt Kennedy International Airport Power Plant ("KIAC") in Queens, N.Y. and
the 40 megawatt Stony Brook Power Plant located at the State University of New
York at Stony Brook on Long Island from Statoil Energy, Inc. The Company paid
approximately $71 million in cash and assumed a capital lease obligation
relating to the Stony Brook Power Plant. The Company initially acquired a 50%
interest in both facilities in December 1997.
Freestone Transaction
On June 15, 2000, the Company announced that it had acquired the Freestone
Energy Center from Energy Corporation. Freestone is a 1,052 megawatt natural
gas-fired energy center under development in Freestone County, Texas. The
technologically advanced energy center is currently under construction, with a
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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
two-phased commercial start-up beginning in June 2002. The Company paid
approximately $61.0 million in cash and assumed certain liabilities. This
represented payment for the land and development rights for the Freestone Energy
Center, previous progress payments made for four General Electric gas turbines,
two steam turbines and related equipment, and development expenditures incurred
to date.
Auburndale Transaction
On June 30, 2000, the Company acquired from Edison Mission Energy the
remaining 50% ownership interest in a 153 megawatt natural gas-fired, combined
cycle cogeneration facility located in Auburndale, Fla. The Company paid
approximately $22.0 million in cash and assumed certain liabilities, including
project level debt. Related to the project level debt was the assumption of an
interest rate swap agreement with a notional amount of $121.5 million at
December 31, 2000, which effectively converts the project level debt's floating
rate to a fixed rate of 6.52% per annum. The Company acquired an initial 50%
ownership interest in the Auburndale Power Plant in October 1997.
Canadian Natural Gas Reserves Transaction
On July 5, 2000, the Company completed three acquisitions of natural gas
reserves for $206.5 million, including the acquisition of Calgary-based Quintana
Minerals Canada Corp. ("QMCC"), three fields in the Gulf of Mexico and natural
gas assets in the Piceance Basin, Colorado and onshore Gulf Coast.
Oneta Transaction
On July 20, 2000, the Company completed the acquisition of the 1,138
megawatt natural gas-fired Oneta Energy Center, under development in Coseta,
Oklahoma, from Panda Energy International, Inc.
Agnews Transaction
On August 16, 2000, the Company acquired the remaining 80% interest in the
Agnews Power Plant, a 29 megawatt natural gas-fired, combined cycle facility
located in San Jose, California from GATX Capital Corporation for a total
purchase price of $4.9 million. The Company first acquired a 20% equity interest
in the Agnews Power Plant in 1990.
Aidlin Transaction
On August 31, 2000, the Company acquired the remaining 45% equity interest
in the Aidlin Power Plant from an affiliate of Sumitomo Corporation for a total
purchase price of $6.4 million. The Company initially acquired a 5% equity
interest in the Aidlin Power Plant in 1989, representing Calpine's first
megawatt of generation. That interest was increased to 55% with the acquisition
of two other partners' interests in 1999. Located in The Geysers region of
northern California, Aidlin is a 20 megawatt power plant.
SkyGen Energy Transaction
On October 12, 2000, the Company completed the acquisition of Northbrook,
Illinois-based SkyGen Energy LLC ("SkyGen") from Michael Polsky and Wisvest
Corporation ("Wisvest"), an affiliate of Wisconsin Energy Corp for a total
purchase price of $359.1 million. The purchase price included cash payments of
$294.2 million and 2,117,742 shares of Calpine common stock (which were valued
in the aggregate at $64.9 million at signing of the letter of intent).
F-46
82
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
TriGas Transaction
On November 15, 2000, the Company acquired TriGas Exploration Inc.
("TriGas"), the Calgary-based oil and gas company, for a total purchase price of
$101.1 million. The purchase price included cash payments of $79.6 million, as
well as assumed net indebtedness of $21.5 million. The acquisition provided
Calpine with natural gas reserves to fuel its proposed Calgary Energy Centre,
and a 26.6% working interest in the East Crossfield Gas Plant, extensive
pipelines and gathering systems and a significant undeveloped land base with
development potential.
PSM Transaction
On December 13, 2000, the Company completed the acquisition of Boca Raton,
Florida-based PSM for a total purchase price of $16.3 million. The purchase
price included cash payments of $5.6 million and 281,189 shares of Calpine
common stock (which were valued in the aggregate at $10.7 million at the closing
of the agreement). Additionally, the agreement provides for five equal
installments of cash payments, totaling $26.7 million, beginning in January
2002, contingent upon future PSM performance. PSM specializes in the design and
manufacturing of turbine hot section blades, vanes, combustors and low emissions
combustion components.
EMI Transaction
On December 15, 2000, the Company completed the acquisition of strategic
power assets from Dartmouth, Massachusetts-based Energy Management, Inc. ("EMI")
for a total purchase price of $145.0 million. The purchase price included cash
payments of $100.0 million and 1,102,601 shares of Calpine common stock (which
were valued in the aggregate at $45.0 million at the closing of the agreement).
Under the terms of the agreement, the Company acquired the remaining interest in
three recently constructed combined-cycle power generating facilities located in
Dighton, Massachusetts, Tiverton, Rhode Island, and Rumford, Maine, as well as
Calpine-EMI Marketing LLC, a joint marketing venture between Calpine and EMI.
Pro Forma Effects of Acquisitions
The table below reflects unaudited pro forma combined results of the
Company, Unocal, the power plants acquired from PG&E, Sheridan, Calistoga,
CogenAmerica, Vintage, KIAC, Stony Brook, Auburndale, QMCC, Agnews, Aidlin,
SkyGen, TriGas, PSM, and EMI as if the acquisitions had taken place at the
beginning of fiscal year 2000 and 1999 (in thousands, except per share amounts):
2000 1999
---------- ----------
Total revenue............................................... $2,497,559 $1,241,805
Income before extraordinary charge.......................... $ 340,354 $ 131,919
Net income.................................................. $ 339,119 $ 130,769
Net income per basic share.................................. $ 1.28 $ 0.62
Net income per diluted share................................ $ 1.15 $ 0.59
In management's opinion, these unaudited pro forma amounts are not
necessarily indicative of what the actual combined results of operations might
have been if the acquisitions had been effective at the beginning of fiscal year
2000 and 1999. In addition, they are not intended to be a projection of future
results and do not reflect all the synergies that might be achieved from
combined operations.
F-47
83
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
5. SALE AND LEASEBACK TRANSACTIONS
On May 7, 1999, the Company entered into a sale and leaseback transaction
of its 12 Sonoma County and 2 Lake County power plants, located at the Geysers,
California, as well as the Sonoma power plant acquired from the Sacramento
Municipal Utility District in 1998. Under the terms of the lease, the Company
received $18.5 million in net proceeds and recorded a deferred gain of $15.2
million, which is being amortized as a reduction of operating lease expense over
the remaining life of the lease.
On November 5, 1999, the Company entered into a sale and leaseback
transaction of its Calistoga plant. Under the terms of the lease, the Company
received $52.8 million in net proceeds and did not record a deferred gain or
loss.
On September 1, 2000, the Company completed a leveraged lease financing
transaction to provide the term financing for both Phase I and Phase II of the
Pasadena, Texas Cogeneration project. Under the terms of the lease, the Company
received $400.0 million in gross proceeds and recorded a deferred gain of
approximately $65.0 million, which is being amortized as a reduction of
operating lease expense over the remaining life of the lease.
On December 19, 2000, the Company completed leveraged lease transactions in
which the Company sold the Tiverton and Rumford facilities (purchased from EMI)
to a single owner lessor for $466.7 million, which then leased the facilities
back to the Tiverton and Rumford subsidiaries. The Company guaranteed the
obligations of the Tiverton and Rumford subsidiaries under the leases. To
finance the transaction, a trust was established to issue $366.0 million of 9.0%
pass through certificates due July 15, 2018, which was effected by a private
placement by the trust under Rule 144A of the Securities Act of 1933. The
Company recorded a deferred gain of approximately $1.7 million, which is being
amortized as a reduction of operating lease expense over the remaining life of
the lease. In connection with this transaction, the Company issued letters of
credit. At December 31, 2000, $52.1 million in letters of credit were
outstanding.
On December 22, 2000, the Company completed a leveraged lease financing
transaction of its West Ford Flat and Bear Canyon projects. Under the terms of
the agreement, the facilities were incorporated into the Company's Geothermal
lease facility, which the Company originally entered into on May 7, 1999. The
Company received $81.0 million in gross proceeds and recorded a deferred loss of
approximately $8.1 million, which is being amortized as an increase of operating
lease expense over the remaining life of the lease.
F-48
84
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
6. INVESTMENTS IN POWER PROJECTS
Investments, which are accounted for under the equity method, are as
follows (in thousands):
OWNERSHIP DECEMBER 31,
INTEREST AS OF --------------------
DECEMBER 31, 2000 2000 1999
----------------- -------- --------
Sumas Power Plant............................. (1) $ -- $ --
Acadia Power Plant............................ 50.0% 108,529 --
Grays Ferry Power Plant....................... 40.0% 30,257 21,875
Aries Power Plant............................. 50.0% 22,350 --
Gordonsville Power Plant...................... 50.0% 18,060 16,496
Lockport Power Plant.......................... 11.4% 14,722 12,406
Bayonne Power Plant........................... 7.5% 8,385 8,490
Tiverton Power Plant(2)....................... 100.0% -- 44,853
Rumford Power Plant(2)........................ 100.0% -- 44,316
Kennedy International Airport Power
Plant(2).................................... 100.0% -- 37,880
Stony Brook Power Plant(2).................... 100.0% -- 21,477
Auburndale Power Plant(2)..................... 100.0% -- 19,565
Dighton Power Plant(2)........................ 100.0% -- 14,875
Other......................................... -- 3,318 992
-------- --------
Total Investments in Power Projects......... $205,621 $243,225
======== ========
- ---------------
(1) See Footnote (1) below detailing the Company's income and distributions from
investments in unconsolidated power projects.
(2) The Company acquired the remaining interests in these facilities in 2000 and
thereafter consolidated the operations.
The combined unaudited results of operations and financial position of the
Company's equity method affiliates are summarized below (in thousands):
DECEMBER 31,
----------------------------------------
2000 1999 1998
---------- ------------ ----------
Condensed Statement of Operations:
Revenue..................................... $ 617,914 $ 562,401 $ 495,123
Gross profit................................ 217,777 245,314 214,382
Income from continuing operations........... 161,852 214,520 199,601
Net income.................................. 80,812 113,837 108,563
Company's share of net income............... 24,639 36,593 25,240
Condensed Balance Sheet:
Current assets.............................. 130,316 167,107 134,794
Non-current assets.......................... 1,424,672 1,306,325 1,240,172
Total assets................................ 1,554,988 1,473,432 1,374,966
Current liabilities......................... 175,764 121,214 110,957
Non-current liabilities..................... 951,013 1,087,329 994,570
Total liabilities........................... 1,126,777 1,208,543 1,105,527
F-49
85
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
The following details the Company's income and distributions from
investments in unconsolidated power projects (in thousands):
INCOME FROM UNCONSOLIDATED
INVESTMENTS IN POWER PROJECTS DISTRIBUTIONS
----------------------------- -----------------------------
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
2000 1999 1998 2000 1999 1998
------- ------- ------- ------- ------- -------
Sumas Power Plant(1)........... $12,951 $21,779 $11,699 $12,951 $21,779 $11,699
Grays Ferry.................... 4,737 (3) -- 4,500 -- --
Lockport Power Plant........... 4,391 4,255 3,628 3,752 3,741 3,297
Gordonsville Power Plant....... 4,514 4,299 3,807 2,950 4,000 3,125
Bayonne Power Plant............ 2,196 3,426 2,446 2,301 2,808 2,701
Stony Brook Power Plant........ (994) 857 252 1,820 370 --
Auburndale Power Plant......... 599 (712) (1,377) 1,350 3,250 2,475
Kennedy International Airport
Power Plant.................. (2,769) 1,968 1,159 -- 3,350 4,100
Other.......................... (986) 724 3,626 355 4,020 320
------- ------- ------- ------- ------- -------
Total................ $24,639 $36,593 $25,240 $29,979 $43,318 $27,717
======= ======= ======= ======= ======= =======
- ---------------
(1) 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.
From January 1, 1998 through December, 2000, the Company recorded income
equal to the amount of cash received from partnership distributions. The
Company received distributions at a rate of 70% of project cashflow until
December, 2000 when a cumulative 24.5% pre-tax rate of return was earned on
its original investment. As a result, the Company's equity interest in the
partnership has been reduced to 0.1%.
The Company provides for deferred taxes to the extent that distributions
exceed earnings.
7. NOTES PAYABLE AND BORROWINGS UNDER LINES OF CREDIT
The components of notes payable and borrowings under lines of credit are
(in thousands):
BORROWINGS LETTERS OF CREDIT
OUTSTANDING OUTSTANDING
DECEMBER 31, DECEMBER 31,
------------------- ------------------
2000 1999 2000 1999
-------- -------- -------- -------
Corporate Revolving Line of Credit.......................... $ 40,000 $ -- $157,900 $28,800
Calpine Canada Note Payable and Borrowings under Line of
Credit.................................................... 144,500 -- 48 --
Calpine Natural Gas Company Line of Credit.................. -- 97,750 -- --
Other....................................................... 12,449 38,420 10,810 10,810
-------- -------- -------- -------
Total Notes Payable and borrowings under lines of
credit........................................... $196,949 $136,170 $168,758 $39,610
-------- -------- -------- -------
Less: Notes Payable and borrowings under lines of credit,
current portion........................................... 1,087 38,867
-------- --------
Notes Payable and borrowings under lines of credit, net of
current portion........................................... $195,862 $ 97,303
======== ========
In May 2000, Calpine entered into an amended and restated $400.0 million,
three-year revolving line of credit with a consortium of commercial lending
institutions with the Bank of Nova Scotia as agent, which replaced an existing
$100.0 million credit facility. A maximum of $200.0 million of the credit
facility may be allocated to letters of credit. At December 31, 2000, the
Company had $40.0 million in borrowings and
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86
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
$157.9 million of letters of credit outstanding under the amended and restated
credit facility. At December 31, 1999, the Company had no borrowings and $28,800
in letters of credit outstanding under this credit facility. Borrowings bear
variable interest and interest is paid on the last day of each interest period
for such loans, at least quarterly. The credit facility specifies that the
Company maintain certain covenants, with which the Company was in compliance as
of December 31, 2000 and 1999. Commitment fees related to this line of credit
are charged based on the unused credit. The interest rate ranged from 7.88% to
9.75% during 2000.
The Company, through its wholly owned Canadian subsidiaries, maintains a
borrowing base in Canada of Cdn. $304.0 million (approximately US $202.7 million
at December 31, 2000) under three facilities. At December 31, 2000, the Company
had US $144.5 million outstanding under these facilities. The facilities bear
interest at variable rates. The weighted average rate for each of the facilities
in 2000 was 8.52%. Additionally, commitment fees of 0.25% accrue on any unused
portion of these facilities. The lines of credit are secured by the Company's
oil and gas reserves in Canada. As of December 31, 2000, the Company was in
compliance with all covenants required under these facilities.
In 1999, the Company, through its wholly owned subsidiary CNGC, maintained
a borrowing base of $99.1 million with Bank One, Texas N.A. under two
facilities. In August 2000, the Company repaid the outstanding balance of $93.3
million and terminated the agreement. As of December 31, 1999, CNGC had total
borrowings of $97.8 million outstanding under this facility. The facility bore
interest at variable rates. At December 31, 1999, the interest rate was 8.6%.
The lines of credit were secured by CNGC's oil and gas properties. The Company
was in compliance with the financial covenants required by the facility as of
December 31, 1999.
Additionally, in connection with repayment of outstanding borrowings in
August 2000, the termination of certain credit agreements and the related
write-off of unamortized deferred financing costs, the Company recorded an
extraordinary loss of $1.2 million after taxes.
F-51
87
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
8. PROJECT FINANCING AND INTEREST RATE SWAP AGREEMENTS
The components of project financing as of December 31, 2000 and 1999 are
(in thousands):
LETTERS OF
INTEREST OUTSTANDING AT CREDIT
RATE(1) DECEMBER 31, OUTSTANDING(3)
----------- --------------------- --------------
PROJECTS 2000 1999 FINAL MATURITY 2000 1999 2000
-------- ---- ---- -------------- ---------- -------- --------------
Calpine Construction Finance
Company(2).................. 8.39% -- 2004 $ 701,644 $ -- $ --
Auburndale Power Plant........ 7.51% -- 2012 121,464 -- --
Newark & Parlin Power
Plants...................... 7.68% 6.51% 2011 116,715 125,318 --
Broad River Energy Center..... 8.02% -- 2007 115,880 -- 34,831
Pine Bluff Energy Center...... 8.22% -- 2018 113,197 -- 21,333
Hog Bayou Energy Center....... 8.24% -- 2002 107,974 -- 29,003
RockGen Energy Center......... 7.97% -- 2007 89,840 -- 16,095
Morris Power Plant............ 7.39% 7.50% 2004 85,600 85,622 --
DePere Energy Center.......... 7.68% -- 2017 47,243 -- 4,444
Dighton Power Plant........... 7.79% -- 2019 32,798 -- --
Pasadena Power Plant.......... -- 5.58% 2005 -- 154,800 --
---------- -------- --------
Total............... 1,532,355 365,740 $105,706
========
Less: current portion......... 58,486 8,603
---------- --------
Long-term project financing... $1,473,869 $357,137
========== ========
- ---------------
(1) Weighted average rate before giving effect to amortization of financing cost
or interest rate swaps. The fair value of each of the project financings
approximates the carrying value.
(2) Represents rate at December 31, 2000.
(3) No letters of credit associated with project financings in 1999.
Calpine Construction Finance Company Debt
In November 1999, the Company entered into a credit agreement for $1.0
billion through its wholly owned subsidiary Calpine Construction Finance Company
L.P. with a consortium of banks with the lead arranger being The Bank of Nova
Scotia and the lead arranger syndication agent being Credit Suisse First Boston.
The non-recourse credit facility is utilized to finance the construction of the
Company's diversified portfolio of gas-fired power plants currently under
development. The Company currently intends to refinance this construction
facility in the long-term capital markets prior to its four-year maturity. As of
December 31, 2000, the Company had $544.8 million in borrowings outstanding
under the facility. Borrowings under this facility bear variable interest. The
credit facility specifies that the Company maintain certain covenants, with
which the Company was in compliance as of December 31, 2000. The interest rate
at December 31, 2000 was 8.44%. The interest rate ranged from 7.38% to 9.50%
during 2000.
In October 2000, the Company entered into a credit agreement for $2.5
billion through its wholly owned subsidiary Calpine Construction Finance Company
II, LLC with a consortium of banks with the lead arrangers being The Bank of
Nova Scotia and Credit Suisse First Boston. The non-recourse credit facility is
utilized to finance the construction of the Company's diversified portfolio of
gas-fired power plants currently under development. The Company currently
intends to refinance this construction facility in the long-term capital markets
prior to its four-year maturity. As of December 31, 2000, the Company had $156.8
million in borrowings outstanding under the facility. Borrowings under this
facility bear variable interest. The credit
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88
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
facility specifies that the Company maintain certain covenants, with which the
Company was in compliance as of December 31, 2000. The interest rate at December
31, 2000 was 8.20%. The interest rate ranged from 8.20% to 10.25% during 2000.
Auburndale Power Plant Debt
As part of the Company's acquisition of the Auburndale Power Plant, the
Company assumed a project loan. This facility provides for project financing
loans aggregating $126.0 million. Amounts outstanding under the facility bear
interest at variable rates. The weighted average interest rate for 2000 was
7.51%. The effective interest rate for 2000, after giving effect to an interest
rate swap, was 7.82%.
Newark & Parlin Power Plant Debt
On December 17, 1999, the Company acquired 80% of the common stock of CGCA
which owns 100% of the Newark and Parlin Power Plants ("Newark & Parlin"). At
December 31, 2000 there was $116.7 million outstanding on a fifteen year
non-recourse term loan which is a joint and severable liability of Newark &
Parlin. The term loan is secured by all Newark & Parlin assets and a pledge of
their capital stock. CGCA has guaranteed repayment of up to $25.0 million of the
term loan based on the principal balance of the loan, and also guaranteed
payment by Newark & Parlin of all income and franchise taxes when due. CGCA's
guarantee is reduced proportionately to the outstanding principal as payments
are made on the debt. The balance of the guarantee was $18.8 million as of
December 31, 2000. The interest rate on the outstanding principal is variable
and averaged 7.68% in 2000. The effective interest rate for 2000, after giving
effect to the interest rate swap, was 8.07%. Interest on the loan is payable at
least quarterly.
Broad River Energy Center Debt
As part of the Company's acquisition of SkyGen, the Company assumed a term
loan and a steam injection addition loan for the Broad River Energy Center. The
steam injection loan is expected to be converted to a term loan in 2001. The
construction loans require only interest payments through the conversion date,
and blended payments of principal and interest following conversion to a term
loan. Interest on the construction loan is variable and averaged 8.02% for 2000.
The effective interest rate for 2000, after giving effect to interest rate
swaps, was 7.34%.
Pine Bluff Energy Center Debt
As part of the Company's acquisition of SkyGen, the Company entered into
construction financing for the Pine Bluff Energy Center. Under the terms of the
credit facility, the Company can borrow up to $142.0 million to fund
construction. Of this amount, $32.0 million is secured by guarantees or letters
of credit from the members or their affiliates. Upon completion of construction,
equity contributions of $32.0 million will be made to repay a portion of the
construction loan and the balance of the construction loan will be converted to
a term loan. The term loan will consist of three tranches: Tranche A in the
amount of $30.0 million with a maturity date of 8 1/2 years from the conversion
date, Tranche B in the amount of $45.0 million with a maturity date of 13 1/2
years from the conversion date, and Tranche C in the amount of $35.0 million
with a maturity date of 17 1/2 years from the conversion date. The construction
loan requires only interest payments through the conversion date, and blended
payments of principal and interest following conversion to a term loan. Interest
on the construction loan is variable and averaged 8.22% during 2000. The
effective interest rate for 2000, after giving effect to interest rate swaps,
was 7.34%.
F-53
89
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Hog Bayou Energy Center Debt
As part of the Company's acquisition of SkyGen, the Company has entered
into an arrangement with a syndicate of commercial banks to obtain financing to
construct the Hog Bayou Energy Center. As part of the related credit agreement,
the lenders will provide a facility to fund construction whereby the Company can
borrow up to $38.0 million under an equity bridge loan and $104.6 million under
a construction loan. The equity bridge loan matures on December 31, 2001 and the
construction loan matures on December 31, 2002. As of December 31, 2000, the
Company has borrowed $38.0 million under the equity bridge loan and $70.0
million under the construction loan. The weighted average interest rate for the
facilities was 8.24% in 2000.
RockGen Energy Center Debt
As part of the Company's acquisition of SkyGen, the Company entered into
financing for the RockGen Energy Center. As part of the related credit
agreement, the lender provided a facility whereby the Company can borrow up to
$152.6 million in construction loans. Upon completion of construction, the
balance of the construction loans will be converted to a term loan which matures
on March 1, 2007. The construction loans require only interest payments through
the conversion date, and blended payments of principal and interest following
the conversion date. The weighted average interest rate during 2000 was 7.97%.
Morris Power Plant Debt
On December 17, 1999, the Company acquired 80% of the common stock of CGCA
which owns 100% of Morris LLC ("Morris"). In 1997, Morris entered into a
construction and term loan agreement to provide non-recourse project financing
for a major portion of the Morris Project. The agreement provides $85.6 million
of 5-year term loan commitments and $5.4 million in letter of credit
commitments. As of December 31, 2000, $85.6 million was outstanding as a term
loan under the agreement and no amounts were pledged under the letter of credit.
Interest on the term loan is variable and averaged 7.39% in 2000. Borrowings are
secured by CGCA's ownership interest in Morris, its cash flows, dividends and
any other property of Morris.
DePere Energy Center Debt
As part of the Company's acquisition of SkyGen, the Company assumed a term
loan. Interest is payable based on the rate of the interest rate swap plus an
applicable margin. The weighted average interest rate, before and after swap
effects, was 7.68% and 6.43%, respectively.
Dighton Power Plant Debt
In December 2000, the Company acquired the remaining interest in the
Dighton Power Plant. The Company assumed project financing for the plant. The
weighted average interest rate as of December 31, 2000 was 7.79%.
Pasadena Power Plant Debt
On January 4, 1999, the Company entered into a credit agreement with ING
(U.S.) Capital LLC ("ING") to provide up to $265.0 million of non-recourse
project financing for the construction of the Pasadena facility expansion. On
August 31, 2000, the Company repaid the outstanding balance of $224.2 million
under the credit agreement.
Additional Interest Rate Swap Agreements
The Company acquired an interest rate swap agreement with the purchase of
the Auburndale Power Plant on June 30, 2000. The agreement was entered into to
fix the project's floating rate debt. The swap fixes
F-54
90
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
the interest rate on a notional amount of $121.5 million at a weighted average
rate of 6.5%. At December 31, 2000, the fair market value of this hedge was
approximately $(3.7) million.
The Company acquired ten interest rate swap agreements with the purchase of
SkyGen on October 12, 2000. The agreements were entered into by SkyGen to fix
the floating rate debt for its RockGen, Broad River, DePere, and Pine Bluff
projects. The swaps fix the interest rates on an aggregate notional amount of
$303.1 million at a weighted average rate of 7.3%. At December 31, 2000, the
fair market value of these hedges was approximately $(16.4) million.
Upon adoption of SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," the hedges will be accounted for using the methodology
described in Note 2.
9. SENIOR NOTES
Senior Notes payable consist of the following as of December 31, 2000 and
1999 (in thousands):
DECEMBER 31, FAIR VALUE AS OF
----------------------- -----------------------
INTEREST RATES FIRST CALL DATE 2000 1999 2000 1999
-------------- --------------- ---------- ---------- ---------- ----------
Senior Notes due
2004................. 9 1/4% 1999 $ 105,000 $ 105,000 $ 105,000 $ 106,050
Senior Notes due
2005................. 8 1/4% (2) 250,000 -- 246,700 --
Senior Notes due
2006................. 10 1/2% 2001 171,750 171,750 178,620 180,939
Senior Notes due
2006................. 7 5/8% (1) 250,000 250,000 239,700 238,050
Senior Notes due
2007................. 8 3/4% 2002 275,000 275,000 266,750 275,963
Senior Notes due
2008................. 7 7/8% (1) 400,000 400,000 380,320 384,600
Senior Notes due
2009................. 7 3/4% (1) 350,000 350,000 332,535 320,950
Senior Notes due
2010................. 8 5/8% (2) 750,000 -- 726,600 --
---------- ---------- ---------- ----------
Total........ $2,551,750 $1,551,750 $2,476,225 $1,506,552
========== ========== ========== ==========
- ---------------
(1) Not redeemable prior to maturity.
(2) Redeemable at any time prior to maturity.
The Company has completed a series of public debt offerings since 1994.
Interest is payable semiannually at specified rates. There are no sinking fund
or mandatory redemptions of principal before the maturity dates of each
offering. Certain of the Senior Note indentures limit the Company's ability to
incur additional debt, pay dividends, sell assets and enter into certain
transactions. As of December 31, 2000 the Company is in compliance with all debt
covenants relating to the Senior Notes.
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 due 2004 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 due 2004 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%.
Senior Notes Due 2005
On August 10, 2000, the Company completed a public offering of $250.0
million of its 8 1/4% Senior Notes due 2005 ("Senior Notes due 2005"). The
Senior Notes due 2005 bear interest at 8 1/4% per year, payable semi-annually on
August 15 and February 15 and mature on August 15, 2005. The Senior Notes due
2005
F-55
91
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
may be redeemed at any time prior to maturity at a redemption price equal to
100% of their principal amount plus accrued and unpaid interest plus a
make-whole premium. The effective interest rate on the $250.0 million, after
amortization of deferred financing costs, was 8.6%.
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 due 2006 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 due 2006 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%.
Additionally, during 1999 the Company completed a public offering of $250.0
million of its 7 5/8% Senior Notes due 2006 ("1999 Senior Notes due 2006"). The
1999 Senior Notes due 2006 bear interest at 7 5/8% per year, payable
semi-annually on April 15 and October 15 and mature on April 15, 2006. The 1999
Senior Notes due 2006 are not redeemable prior to maturity. The effective
interest rate on the $250.0 million, after amortization of deferred financing
costs, was 7.9%.
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 due 2007 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 due 2007 from the
proceeds of any public equity offering. The effective interest rate on the
$275.0 million, after amortization of deferred financing costs, was 9.1%.
Senior Notes Due 2008
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 due 2008 are not redeemable prior to maturity. The effective
interest rate on the $400.0 million, after amortization of deferred financing
costs, was 8.0%.
Senior Notes Due 2009
The Senior Notes due 2009 bear interest at 7 3/4% per year, payable
semi-annually on April 15 and October 15 and mature on April 15, 2009. The
Senior Notes due 2009 are not redeemable prior to maturity. The effective
interest rate on the $350.0 million, after amortization of deferred financing
costs, was 7.9%. Senior Notes Due 2010
On August 10, 2000, the Company completed a public offering of $750.0
million of its 8 5/8% Senior Notes due 2010 ("Senior Notes due 2010"). The
Senior Notes due 2010 bear interest at 8 5/8% per year, payable semi-annually on
August 15 and February 15 and mature on August 15, 2010. The Senior Notes due
2010 may be redeemed at any time prior to maturity at a redemption price equal
to 100% of their principal amount plus accrued and unpaid interest plus a
make-whole premium. The effective interest rate on the $750.0 million, after
amortization of deferred financing costs, was 8.7%.
F-56
92
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Annual Debt Maturities
The annual principal maturities of the borrowings under lines of credit,
project financings, notes payable and senior notes as of December 31, 2000 are
as follows (in thousands):
2001..................................................... $ 59,573
2002..................................................... 96,033
2003..................................................... 612,552
2004..................................................... 367,554
2005..................................................... 279,964
Thereafter............................................... 2,865,378
----------
Total.......................................... $4,281,054
==========
10. CAPITAL LEASE OBLIGATIONS
During 2000, the Company assumed and began to consolidate capital leases in
conjunction with the acquisitions of the Hidalgo Energy Center, the Stony Brook
Power Plant and the Agnews Power Plant. The asset balances for the leased assets
totaled $181.7 million at December 31, 2000, with accumulated amortization of
$3.4 million.
The following is a schedule by years of future minimum lease payments under
capital leases together with the present value of the net minimum lease payments
as of December 31, 2000 (in thousands):
Year Ending December 31:
2001........................................................ $ 17,215
2002........................................................ 17,174
2003........................................................ 17,956
2004........................................................ 18,223
2005........................................................ 18,369
Thereafter.................................................. 349,562
---------
Total minimum lease payments...................... 438,499
---------
Less: Amount representing interest(1)....................... (227,638)
---------
Present value of net minimum lease payments............... $ 210,861
=========
Less: Capital lease obligation, current portion............. (1,985)
---------
Capital lease obligation, net of current portion.......... $ 208,876
=========
- ---------------
(1) Amount necessary to reduce net minimum lease payments to present value
calculated at the implicit interest rates of the leases at their inception.
11. TRUST PREFERRED SECURITIES
In 1999 and 2000, the Company, through its wholly-owned subsidiaries,
Calpine Capital Trust, Calpine Capital Trust II and Calpine Capital Trust III,
statutory business trusts created under Delaware law, (collectively, "the
Trusts") completed offerings of Remarketable Term Income Deferrable Equity
Securities ("trust preferred securities" or "HIGH TIDES") at a value of $50.00
per share. In 1999, the Company and Calpine Capital Trust had a private
placement of 5,520,000 shares, including the purchasers' option. In January and
February of 2000 the Company and Calpine Capital Trust II privately placed
7,200,000 shares, including the purchasers' option. In August 2000, the Company
and Calpine Capital Trust III privately placed
F-57
93
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
10,350,000 shares, including the underwriters' over-allotment option. At
December 31, 2000, the balance for each of these issuances was $268.2, $350.9
and $503.4, respectively.
The net proceeds from each of the offerings were used by the Trusts to
invest in convertible subordinated debentures of the Company, which represent
substantially all of the respective trusts' assets. The Company has effectively
guaranteed all of the respective trusts' obligations under the trust preferred
securities. The trust preferred securities accrue distributions at rates of
5 3/4%, 5 1/2% and 5% per annum, respectively, and have liquidation values of
$50.00 per share. The Company has the right to defer the interest payments on
the debentures for up to twenty consecutive quarters, which would also cause a
deferral of distributions on the trust preferred securities. Currently, the
Company has no intention of deferring interest payments on the debentures. The
trust preferred securities are convertible into shares of the Company's common
stock at the holder's option on or prior to the tender notification date, at
rates of 3.4260, 1.9524 and 1.1510 shares, respectively, of common stock for
each trust preferred security.
The 1999 issuance may be redeemed at any time on or after November 5, 2002
at a redemption price equal to 101.44% of the principal amount plus any accrued
and unpaid interest declining to 100% of the principal amount on or after
November 5, 2003. The second issuance of HIGH TIDES may be redeemed at any time
on or after February 5, 2003 at a redemption price equal to 101.375% of the
principal amount plus any accrued and unpaid distributions declining to 100% of
the principal amount on or after February 5, 2004. The August 2000 issuance may
be redeemed at any time on or after August 5, 2003 at a redemption price equal
to 101.25% of the principal amount plus any accrued and unpaid distributions
declining to 100% of the principal amount on or after August 5, 2004.
12. PROVISION FOR INCOME TAXES
The components of the deferred income taxes, net as of December 31, 2000
and 1999 are as follows (in thousands):
2000 1999
--------- ---------
Expenses deductible in a future period...................... $ 27,896 $ 7,949
Net operating loss and credit carryforwards................. 41,472 50,358
Other differences........................................... 290 1,545
--------- ---------
Deferred tax assets....................................... 69,658 59,852
--------- ---------
Property differences........................................ (621,082) (340,164)
Difference in taxable income and income from investments
recorded on the equity method............................. -- (2,305)
Other differences........................................... (15,868) (8,841)
--------- ---------
Deferred tax liabilities.................................. (636,950) (351,310)
--------- ---------
Net deferred income taxes.............................. $(567,292) $(291,458)
========= =========
The net operating loss and credit carryforwards consist of federal and
state net operating loss carryforwards which expire 2005 through 2014 and
federal depletion deduction carryforwards which can be carried forward
indefinitely. The federal and state net operating loss carryforwards available
are subject to limitations on annual usage. It is expected that they will be
fully utilized before expiring. At December 31, 2000, federal and state
alternative minimum tax credit carryforwards were fully utilized. 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 carryforward period are reduced.
F-58
94
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
The provision for income taxes for the years ended December 31, 2000, 1999
and 1998 consists of the following (in thousands):
2000 1999 1998
-------- ------- -------
Current:
Federal............................................ $214,169 $26,564 $ 1,582
State.............................................. 40,596 6,728 277
Foreign............................................ -- -- --
Deferred:
Federal............................................ (30,573) 23,142 26,830
State.............................................. (7,852) 4,305 1,772
Adjustment in state tax rate (net of federal
benefit)...................................... -- -- (4,826)
Revision in prior years' tax estimates.......... -- 1,234 1,419
Foreign............................................ 2,611 -- --
-------- ------- -------
Total provision............................ $218,951 $61,973 $27,054
======== ======= =======
The Company's effective rate for income taxes for the years ended December
31, 2000, 1999 and 1998 differs from the United States statutory rate, as
reflected in the following reconciliation:
2000 1999 1998
---- ---- ----
United States statutory tax rate............................ 35.0% 35.0% 35.0%
State income tax, net of federal benefit.................... 3.9 3.6 3.8
Depletion allowance......................................... -- -- (1.5)
Foreign tax at rates other than U.S. statutory.............. 0.5 -- --
Other, net.................................................. 0.9 0.6 (0.4)
---- ---- ----
Effective income tax rate................................. 40.3% 39.2% 36.9%
==== ==== ====
13. 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 are
immediately eligible upon hire. Contributions include employee salary deferral
contributions and a 3% employer profit-sharing contribution. Employer
profit-sharing contributions in 2000, 1999 and 1998 totaled $3.1 million, $1.3
million and $829,000, respectively.
1996 Employee Stock Purchase Plan
The Company adopted the 1996 Employee Stock Purchase Plan in July 1996.
Eligible employees could purchase up to 2,200,000 shares of common stock at
semi-annual intervals through periodic payroll deductions. Purchases were
limited to 15 percent of an employee's eligible compensation, and to a maximum
value of $25,000 per calendar year based on the IRS code Section 423 limitation.
Shares were purchased on January 31, and the plan terminated on February 1,
2000. Under the 1996 plan, 408,300 shares were issued at a weighted average fair
value of $2.67 per share in 2000. 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.
F-59
95
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
2000 Employee Stock Purchase Plan
The Company adopted the 2000 Employee Stock Purchase Plan ("ESPP") in May
2000. Eligible employees may purchase up to 4,000,000 shares of common stock at
semi-annual intervals through periodic payroll deductions. Purchases are limited
to a maximum value of $25,000 per calendar year based on the IRS code Section
423 limitation. Shares are purchased on May 31 and November 30 of each year
until termination of the plan on May 30, 2002. Under the ESPP, 221,853 shares
were issued at a weighted average fair value of $23.18 per share in 2000. 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):
2000 1999 1998
-------- ------- -------
Net income............................. As reported $323,452 $95,093 $45,678
Pro Forma 304,544 84,928 42,454
Earnings per share data:
Basic earnings per share............. As reported $ 1.22 $ 0.45 $ 0.28
Pro Forma 1.15 0.41 0.26
Diluted earnings per share........... As reported $ 1.10 $ 0.43 $ 0.27
Pro Forma 1.04 0.38 0.25
The fair value of options granted in 2000, 1999 and 1998 was $15.33, $5.60
and $2.77 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 67% for 2000, 69% for 1999 and 35% for 1998, risk-free
interest rates of 6.69% for 2000, 5.74% for 1999, 5.25% for 1998, respectively,
and expected lives of 7 years for 2000, 1999 and 1998.
As of December 31, 2000, the Company had granted options to purchase
36,849,010 shares of common stock, net of cancellations. Over the life of the
SIP, options exercised have equaled 7,337,624, leaving 29,511,386 granted and
not yet exercised. Under the SIP, the option exercise price generally equals the
stock's fair market value on date of grant. The SIP options generally vest
ratably over four years and expire after
F-60
96
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
10 years. Changes in options outstanding, granted, exercisable and cancelled by
the Company during the years 2000, 1999 and 1998, under the option plan were as
follows:
AVAILABLE FOR WEIGHTED
OPTION OR NUMBER OF AVERAGE
AWARD SHARES EXERCISE PRICE
------------- ---------- --------------
Outstanding January 1, 1998................... 12,418,657 20,158,424 $ 0.75
Additional shares reserved.................. 1,604,856 -- --
Granted.................................. (3,365,800) 3,365,800 2.13
Exercised................................ -- (270,320) 0.37
Cancelled................................ 178,384 (178,384) 1.96
---------- ----------
Outstanding December 31, 1998................. 10,836,097 23,075,520 0.95
Additional shares reserved.................. 1,612,927 -- --
Granted.................................. (8,247,848) 8,247,848 6.08
Exercised................................ -- (1,380,944) 0.72
Cancelled................................ 29,600 (29,600) 4.06
---------- ----------
Outstanding December 31, 1999................. 4,230,776 29,912,824 2.37
Additional shares reserved.................. 2,522,157 --
Granted.................................. (4,061,142) 4,061,142 22.17
Exercised................................ -- (4,341,112) 1.10
Cancelled................................ 121,468 (121,468) 13.60
---------- ----------
Outstanding December 31, 2000................. 2,813,259 29,511,386 $ 5.24
========== ==========
Options exercisable:
December 31, 1998........................... 15,414,440 $ 0.55
December 31, 1999........................... 17,410,052 0.74
December 31, 2000........................... 18,557,646 $ 2.25
The following tables summarizes information concerning outstanding and
exercisable options at December 31, 2000:
OUTSTANDING OPTIONS
------------------------------------- OPTIONS EXERCISABLE
WEIGHTED ---------------------
AVERAGE WEIGHTED WEIGHTED
REMAINING AVERAGE AVERAGE
NUMBER OF CONTRACTUAL EXERCISE NUMBER OF EXERCISE
RANGE OF EXERCISE PRICES SHARES LIFE IN YEARS PRICE SHARES PRICE
- ------------------------ ---------- ------------- -------- ---------- --------
$ 0.065 - $ 0.065 5,156,560 2.00 $ 0.065 5,156,560 $0.065
$ 0.570 - $ 0.615 3,976,896 4.09 0.597 3,976,896 0.597
$ 0.645 - $ 1.070 2,999,856 5.30 1.060 2,999,856 1.060
$ 1.105 - $ 2.250.. 5,305,492 6.79 2.173 3,148,092 2.167
$ 2.345 - $ 3.320 645,950 7.07 2.856 587,950 2.895
$ 3.750 - $ 3.860 4,032,250 8.12 3.859 896,650 3.859
$ 4.240 - $ 9.955 3,398,266 8.57 9.136 933,354 8.935
$ 10.000 - $ 23.190 3,641,362 6.57 20.129 849,482 17.983
$ 23.205 - $ 51.282 323,754 9.58 38.092 8,806 30.845
$100.000 - $100.000 31,000 9.70 100.000 -- --
---------- ----------
Total 29,511,386 5.84 $ 5.239 18,557,646 $2.250
========== ==========
F-61
97
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
14. STOCKHOLDERS' EQUITY
Common Stock
Stock Splits -- On September 20, 1999, the Board of Directors authorized a
two-for-one stock split of the Company's common stock, in the form of a stock
dividend, effective October 7, 1999, payable to stockholders of record as of
September 28, 1999. The Company transferred $27,000 to common stock from
additional paid-in capital, representing the aggregate par value of the shares
issued under the stock split.
On May 18, 2000, the Board of Directors authorized a two-for-one stock
split of the Company's common stock, in the form of a stock dividend, effective
June 8, 2000, payable to stockholders of record as of May 29, 2000. The Company
transferred $64,000 to common stock from additional paid-in capital,
representing the aggregate par value of the shares issued under the stock split.
On October 23, 2000, the Board of Directors authorized a two-for-one stock
split of the Company's common stock, in the form of a stock dividend, effective
November 14, 2000, payable to stockholders of record as of November 6, 2000. The
Company transferred $140,000 to common stock from additional paid-in capital,
representing the aggregate par value of the shares issued under the stock split.
All references to the number of common shares and the per common share
amounts have been restated to give retroactive effect to the above stock splits
for all periods presented.
Equity Offering -- On August 9, 2000, Calpine completed a public offering
of 23,000,000 shares of common stock at $34.75 per share. The gross proceeds
from the offering were $799.3 million.
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, 2000, there were 283,715,058 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-62
98
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
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.
15. SIGNIFICANT CUSTOMERS
The Company has two significant customers, Pacific Gas & Electric Company
("PG&E") and Texas Utilities Electric Company ("TUEC"), each of which has
accounted for 10% or more of the Company's annual consolidated revenues for
certain years between 1998 and 2000. PG&E is the regulated subsidiary of PG&E
Corporation. The information on PG&E, disclosed below, excludes PG&E
Corporation's non-regulated subsidiary activity. The Company has transactions
with certain of the non-regulated subsidiaries which have not been affected by
PG&E's solvency problems.
Revenues earned from these sources for the years ended December 31, 2000,
1999 and 1998 were as follows (in thousands):
2000 1999 1998
-------- -------- --------
REVENUES:
PG&E(1)......................... $624,458 $215,264 $222,593
TUEC............................ 184,017 144,016 128,724
Receivables at March 9, 2001, December 31, 2000, and 1999 were as follows
(in thousands):
MARCH 9,
2001 2000 1999
--------------------- -------- --------
(UNAUDITED ESTIMATES)
RECEIVABLES:
PG&E Accounts Receivable......... 231,88$8....... $204,448 $ 33,251
PG&E Notes Receivable(2)......... 65,561........ 62,336 13,919
-------- -------- --------
PG&E Total............. 297,44$9....... $266,784 $ 47,170
======== ======== ========
TUEC Accounts Receivable......... 15,542$........ $ 25,397 $ 9,918
- ---------------
(1) See Note 19 for further discussion of the California energy situation.
(2) Payments of the notes receivable are scheduled from February 2003 until
September 2014 (See Note 2 for further discussion).
As of March 9, 2001, the Company had received from PG&E subsequent accounts
receivable collections of $94.1 million relating to the balances outstanding at
December 31, 2000. These collections represent 100% of November 2000 billings
and approximately 15% of December billings. Additionally, the Company collected
approximately 15% of amounts billed to PG&E in January 2001. The Company
continues to sell power to PG&E pursuant to its long-term contracts and believes
that the accounts receivable will ultimately be collected. However, the
situation in California is highly uncertain and the Company cannot predict the
outcome or the timing of payments from PG&E for past due amounts.
The Company also had combined accounts receivable balances of $45.2 million
as of December 31, 2000 due from the California Independent System Operator
Corporation ("CAISO") and Automated Power Exchange, Inc. ("APX"). As of March 9,
2001, subsequent collections and 2001 activity resulted in a receivable balance
of approximately $8.8 million due from these two entities. CAISO's ability to
pay the Company is directly impacted by PG&E's ability to pay CAISO. APX's
ability to pay the Company is impacted by PG&E's ability to pay the California
Power Exchange ("PX"), which in turn pays APX for
F-63
99
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
energy deliveries by the Company through APX. The Company has provided for a
reserve against collection uncertainties for these receivables, which we believe
to be adequate.
16. SERVICE CONTRACT REVENUE AND EXPENSE
Service contract revenue and service contract expense consists primarily of
risk management, scheduling, balancing, hedging, and related transactions
entered into by CES for the purpose of maintaining operating margins of its
generating assets. The cost of purchased electricity and gas that is resold is
recorded as service contract expense, while the revenue from the resale is
recorded as service contract revenue. The table below shows the composition of
these accounts (in thousands):
2000 1999
-------- -------
Service contract revenue
Electric power sales...................................... $366,388 $23,157
Natural gas sales......................................... 109,043 14,416
Operations and maintenance (O&M) and other................ 4,803 6,200
-------- -------
Total............................................. $480,234 $43,773
======== =======
Service contract expense
Electric power purchases.................................. $365,180 $20,681
Natural gas purchases..................................... 97,336 12,646
Operations and maintenance (O&M) and other................ 6,984 6,909
-------- -------
Total............................................. $469,500 $40,236
======== =======
17. 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
dilutive effect of the assumed conversion of certain trust preferred securities
into the Company's common stock is based on the dilutive common share
equivalents and the after tax distribution expense avoided upon conversion. The
reconciliation of basic earnings per common share to diluted earnings per share
is shown in
F-64
100
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
the following table (in thousands except per share data). All share data has
been adjusted to reflect the two-for-one stock splits effective October 7, 1999,
June 8, 2000, and November 14, 2000.
FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------------------------
2000 1999 1998
--------------------------- -------------------------- --------------------------
NET NET NET
INCOME SHARES EPS INCOME SHARES EPS INCOME SHARES EPS
-------- ------- ------ ------- ------- ------ ------- ------- ------
BASIC EARNINGS PER COMMON SHARE:
Income before extraordinary charge...... $324,687 264,799 $ 1.23 $96,243 209,314 $ 0.46 $46,319 160,969 $ 0.29
Extraordinary charge net of tax benefit
of $796, $793 and $441 for 2000, 1999
and 1998 respectively................. 1,235 (0.01) 1,150 (0.01) 641 (0.01)
-------- ------- ------ ------- ------- ------ ------- ------- ------
Net income.............................. $323,452 264,799 $ 1.22 $95,093 209,314 $ 0.45 $45,678 160,969 $ 0.28
======== ======= ====== ======= ======= ====== ======= ======= ======
Common shares issuable upon exercise of
stock options using treasury stock
method................................ 15,977 13,330 8,342
------- ------- -------
DILUTED EARNINGS PER COMMON SHARE:
Income before extraordinary charge and
dilutive effect of certain trust
preferred securities.................. $324,687 280,776 $ 1.16 $96,243 222,644 $ 0.43 $46,319 169,311 $ 0.27
Dilutive effect of certain trust
preferred securities.................. 20,841 31,746 (0.05) -- -- -- -- -- --
Income before extraordinary charge...... 345,528 312,522 1.11 96,243 222,644 0.43 46,319 169,311 0.27
Extraordinary charge net of tax benefit
of $796, $793, and $441 for 2000, 1999
and 1998 respectively................. 1,235 (0.01) 1,150 -- 641 --
-------- ------- ------ ------- ------- ------ ------- ------- ------
Net income.............................. $344,293 312,522 $ 1.10 $95,093 222,644 $ 0.43 $45,678 169,311 $ 0.27
======== ======= ====== ======= ======= ====== ======= ======= ======
The Company recognized an extraordinary charge of $1.2 million, or $0.01
per share (net of tax benefit of $796,000) in 2000, representing the write-off
of deferred financing costs related to the termination of certain financing
arrangements described in Note 7.
In 1999, the Company recognized an extraordinary charge of $1.2 million or
$0.01 per share (net of tax benefit of $793,000) in April of 1999, representing
the write-off of deferred financing costs related to non-recourse project
financing for the Gilroy Power Plant. The financing agreement was terminated and
the outstanding balance as of April 1999 of $120.6 million was repaid.
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 256,370 shares and 240
shares of the Company's common stock during the year ended December 31, 2000 and
1999, respectively, were not included in the computation of diluted shares
outstanding because such inclusion would be anti-dilutive. There were no
anti-dilutive unexercised employee stock options during the year ended December
31, 1998.
18. COMMITMENTS AND CONTINGENCIES
Production Royalties and Leases -- The Company is committed under numerous
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 prior to May, 1999 when the Company consolidated the
steam field and power plant operations at The Geysers, royalties accrued at
rates ranging from 3% to 14% of steam and effluent revenue. Following the
consolidation of operations, the royalties began to accrue as a percentage of
electrical revenues. Certain properties also have net profits and overriding
royalty interests ranging from approximately 1% to 28%, which are in addition to
the
F-65
101
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
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.
Production royalties and lease expense for the years ended December 31,
2000, 1999 and 1998 are $32.3 million, $13.8 million and $10.7 million,
respectively.
Natural Gas Purchases -- The Company enters into gas purchase contracts of
various terms with third parties to supply gas to its gas-fired cogeneration
projects.
Office and Equipment Leases -- The Company leases its corporate office and
regional offices under noncancellable operating leases expiring through 2011.
Future minimum lease payments under these leases are as follows (in thousands):
2001...................................................... $ 10,122
2002...................................................... 15,822
2003...................................................... 15,118
2004...................................................... 12,275
2005...................................................... 10,965
Thereafter................................................ 50,279
--------
Total........................................... $114,581
========
Lease payments are subject to adjustments for the Company's pro rata
portion of annual increases or decreases in building operating costs. In 2000,
1999 and 1998 rent expense for noncancellable operating leases amounted to $5.0
million, $3.1 million and $1.2 million, respectively.
Cogeneration Facilities Operating Leases -- The Company has entered into
long-term operating leases for cogeneration facilities and combined-cycle power
generating facilities, expiring through 2048. Future minimum lease payments
under these leases are as follows (in thousands):
INITIAL YEAR 2001 2002 2003 2004 2005 THEREAFTER TOTAL
------------ -------- -------- -------- -------- -------- ---------- ----------
Watsonville............... 1995 $ 2,905 $ 2,905 $ 2,905 $ 2,905 $ 2,905 $ 12,779 $ 27,304
King City................. 1996 21,015 21,848 22,781 13,975 10,585 119,426 209,630
Greenleaf................. 1998 9,070 8,990 8,994 8,858 8,723 62,928 107,563
Geysers................... 1999 50,102 69,408 61,135 48,902 50,300 257,690 537,537
KIAC...................... 2000 22,126 25,227 25,467 24,251 24,077 336,812 457,960
Rumford/Tiverton.......... 2000 21,746 32,940 32,940 35,365 44,942 755,292 923,225
Pasadena.................. 2000 36,941 31,600 131,018 26,907 27,777 511,124 765,367
Aries..................... 2000 -- 27,647 28,577 26,853 27,753 446,084 556,914
-------- -------- -------- -------- -------- ---------- ----------
Total............. $163,905 $220,565 $313,817 $188,016 $197,062 $2,502,135 $3,585,500
======== ======== ======== ======== ======== ========== ==========
In 2000, 1999 and 1998, rent expense for cogeneration facilities operating
leases amounted to $69.4 million, $33.6 million and $15.7 million, respectively.
The Watsonville operating lease provides for additional contingent rents payable
during the period from July through December. Contingent rent expense for 2000,
1999 and 1998 amounted to $6.8 million, $393,000 and $1.5 million, respectively.
The King City operating lease commitment is supported by $88.3 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.
At December 31, 2000, the Company is under contract or letter of intent
with certain companies for 228 gas and steam turbines for a total purchase price
of $6.7 billion (of which $1.8 billion had been paid as of December 31, 2000).
F-66
102
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Approximate future payments relating to these turbines are as follows (in
thousands):
2001........................................................ $1,529,184
2002........................................................ 1,374,271
2003........................................................ 1,406,151
2004........................................................ 531,832
2005........................................................ 50,522
Thereafter.................................................. 5,052
----------
Total....................................................... $4,897,012
==========
Litigation
An action was filed against Lockport Energy Associates, L.P. 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 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. On September 29, 2000,
the New York Federal District Court dismissed NYSEG's complaint and NYPSC's
cross-claim. The Court stated that FERC has no authority to alter or waive its
regulations or exemptions to alter the terms of the applicable power purchase
agreements and that Qualifying Facilities are entitled to the benefit of their
bargain, even if at the expense of NYSEG and its ratepayers. NYSEG has filed an
appeal with respect to this decision. In any event, the Company retains the
right to require The Brooklyn Union Gas Company to purchase its 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.
19. SUBSEQUENT EVENTS
California Power Market
During 2000, a combination of factors including increased volatility of
natural gas prices, a significant number of facilities undergoing planned and
unplanned major maintenance, and the decreased availability of energy for
importation from neighboring states resulted in wholesale power prices
significantly higher than historical levels. At the same time, two major
California utilities that are subject to a retail rate freeze, including PG&E,
have faced wholesale prices that far exceed the retail prices they are permitted
to charge, resulting in a significant underrecovery of their costs. On January
16 and 17, 2001, PG&E's credit and debt ratings were lowered by Moody's and S&P
to "junk" or "near junk" status. On January 30, 2001, the PX suspended operation
of its "day ahead" and "day of" markets. On February 1, 2001, PG&E indicated
that it intended to default on payments of over $1 billion due to the PX and
qualifying facilities. PG&E has defaulted under its payment obligations to the
Company (See Note 15).
On February 7, 2001, the Company announced the signing of a 10-year, $4.6
billion fixed-price contract with the California Department of Water Resources
("DWR") to provide electricity to the State of California. The Company committed
to sell up to 1,000 megawatts of electricity, with initial deliveries of
F-67
103
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
200 megawatts starting October 1, 2001 and increasing to 1,000 megawatts by
January 1, 2004. This contract will continue through 2011. The electricity will
be sold directly to DWR, on a 24-hour, 7-day-a-week basis.
On February 28, 2001, the Company announced the signing of two long-term
power sales contracts with the DWR. Under the terms of the first contract, a
$5.2 billion, 10-year, fixed price contract, Calpine commits to sell up to 1,000
megawatts of generation. Initial deliveries are scheduled to begin July 1, 2001
with 200 megawatts and increase to 1,000 megawatts by as early as July 2002.
Under the terms of the second contract, a 20-year contract totaling up to $3.1
billion, Calpine will supply DWR with up to 495 megawatts of peaking generation,
beginning with 90 megawatts as early as August 2001, and increasing up to 495
megawatts as early as August 2002.
On March 13, 2001, the Company announced the signing of a two-month deal to
provide 555 megawatts of electricity to DWR effective immediately through May
15, 2001.
Other Subsequent Events
On February 8, 2001, the Company announced plans to acquire all of the
common shares of Encal Energy Ltd. ("Encal"), a Calgary, Alberta-based natural
gas and petroleum exploration and development company, through a stock-for-stock
exchange in which Encal shareholders will receive Cdn. $12.00 per share in
Calpine common equivalent shares based on an exchange ratio to be determined
prior to closing. The aggregate value of the transaction, for which the Company
expects to use pooling of interests accounting, is approximately $1.2 billion,
including the assumed indebtedness of Encal. Upon completion of the acquisition,
we will gain approximately 1.0 trillion cubic feet equivalent of proved and
provable natural gas reserves, net of royalties. This transaction also provides
access to firm gas transportation capacity from western Canada to California and
the eastern U.S., and an accomplished management team capable of leading our
business expansion in Canada. With the addition of Encal's assets, which
currently produce approximately 230 million cubic feet of gas equivalent
("mmcfe") per day, net of royalties, our net production is expected to increase
to 390 mmcfe per day in North America, enough to fuel approximately 2,300
megawatts of our power fleet. The Company expects to close this transaction
during the second quarter of 2001.
On February 15, 2001, the Company completed a public offering of $1.15
billion of its 8 1/2% Senior Notes Due 2011 ("Senior Notes Due 2011"). The
Senior Notes Due 2011 bear interest at 8 1/2% per year, payable semi-annually on
August 15 and February 15 and mature on February 15, 2011. The Senior Notes Due
2011 may be redeemed at any time prior to maturity at a redemption price equal
to 100% of their principal amount plus accrued and unpaid interest plus a
make-whole premium.
20. 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.
F-68
104
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
The Company's common stock has been traded on the New York Stock Exchange
since September 19, 1996. There were 547 common stockholders of record at
December 31, 2000. No dividends were paid for the years ended December 31, 2000
and 1999. All share data has been adjusted to reflect the two-for-one stock
split effective October 7, 1999, the two-for-one stock split effective June 8,
2000, and the two-for-one stock split effective November 14, 2000.
QUARTER ENDED
---------------------------------------------------
DECEMBER 31, SEPTEMBER 30, JUNE 30, MARCH 31,
------------ ------------- -------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
2000
Total revenue............................. $1,004,817 $678,891 $363,683 $235,402
Gross profit.............................. 247,195 294,168 124,079 58,675
Income from operations.................... 191,398 262,233 102,516 46,301
Income before extraordinary charge........ 107,746 147,108 51,706 18,127
Extraordinary charge...................... -- 1,235 -- --
Net income................................ $ 107,746 $145,873 $ 51,706 $ 18,127
Basic earnings per common share:
Income before extraordinary charge...... $ 0.38 $ 0.55 $ 0.20 $ 0.07
Extraordinary charge.................... -- (0.01) -- --
Net income.............................. 0.38 0.54 0.20 0.07
Diluted earnings per common share:
Income before extraordinary charge and
dilutive effect of certain trust
preferred securities................. $ 0.36 $ 0.52 $ 0.19 $ 0.07
Dilutive effect of certain trust
preferred securities................. (0.02) (0.04) -- --
Income before extraordinary charge...... 0.34 0.48 0.19 0.07
Extraordinary charge.................... -- (0.01) -- --
Net income.............................. 0.34 0.47 0.19 0.07
Common stock price per share:
High.................................... $ 52.97 $ 52.25 $ 35.22 $ 30.75
Low..................................... 32.25 32.25 18.13 16.09
F-69
105
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
QUARTER ENDED
---------------------------------------------------
DECEMBER 31, SEPTEMBER 30, JUNE 30, MARCH 31,
------------ ------------- -------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1999
Total revenue..................................... $247,446 $253,021 $196,625 $150,643
Gross profit...................................... 86,642 102,951 60,805 35,487
Income from operations............................ 66,189 87,105 48,789 24,419
Income before extraordinary charge................ 30,766 42,917 18,710 3,850
Extraordinary charge.............................. -- -- 1,150 --
Net income........................................ $ 30,766 $ 42,917 $ 17,560 $ 3,850
Basic earnings per common share:
Income before extraordinary charge.............. $ 0.13 $ 0.20 $ 0.09 $ 0.02
Extraordinary charge............................ -- -- (0.01) --
Net income...................................... 0.13 0.20 0.08 0.02
Diluted earnings per common share:
Income before extraordinary charge.............. $ 0.12 $ 0.19 $ 0.08 $ 0.02
Extraordinary charge............................ -- -- (0.01) --
Net income...................................... 0.12 0.19 0.07 0.02
Common stock price per share:
High............................................ $ 16.38 $ 11.97 $ 7.38 $ 4.67
Low............................................. 10.63 6.85 4.39 3.16
F-70
106
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
BALANCE AT CHARGED TO BALANCE AT
DESCRIPTION BEGINNING OF YEAR EXPENSE DEDUCTIONS END OF YEAR
----------- ----------------- ---------- ---------- --------------
Year Ended December 31, 2000
Allowance for Doubtful Accounts...... $3,343 $13,454 $(5,719) $11,078
Reserve for Notes Receivable......... -- 4,513 -- 4,513
Year Ended December 31, 1999
Allowance for Doubtful Accounts...... $ 238 $ 3,105 $ -- $ 3,343
Reserve for Notes Receivable......... -- -- -- --
S-1
107
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.1.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.*
3.1.2 Certificate of Correction of Calpine Corporation.(*)
3.1.3 Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation.(*)
3.1.4 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation.(*)
3.2 Amended and Restated Bylaws of Calpine Corporation, a
Delaware corporation.(d)
4.1.1 Indenture dated as of February 17, 1994 between the Company
and State Street Bank and Trust Company (successor trustee
to Shawmut Bank of Connecticut, National Association), as
Trustee, including form of Notes.(a)
4.1.2 First Supplemental Indenture dated as of July 31, 2000
between the Company and State Street Bank and Trust Company
(successor trustee to Shawmut Bank Connecticut, National
Association), as Trustee.(*)
4.2.1 Indenture dated as of May 16, 1996 between the Company and
Fleet National Bank, as Trustee, including form of Notes.(c)
4.2.2 First Supplemental Indenture dated as of August 1, 2000
between the Company and State Street Bank and Trust Company
(successor trustee to Fleet National Bank), as Trustee.(*)
4.3.1 Indenture dated as of July 8, 1997 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(e)
4.3.2 Supplemental Indenture dated as of September 10, 1997
between the Company and The Bank of New York, as Trustee.(q)
4.3.3 Second Supplemental Indenture dated as of July 31, 2000
between the Company and The Bank of New York, as Trustee.(*)
4.4.1 Indenture dated as of March 31, 1998 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(g)
4.4.2 Supplemental Indenture dated as of July 24, 1998 between the
Company and The Bank of New York, as Trustee.(g)
4.4.3 Second Supplemental Indenture dated as of July 31, 2000
between the Company and The Bank of New York, as Trustee.(*)
4.5.1 Indenture dated as of March 29, 1999 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(h)
4.5.2 First Supplemental Indenture dated as of July 31, 2000
between the Company and The Bank of New York, as Trustee.(*)
4.6.1 Indenture dated as of March 29, 1999 between the Company and
The Bank of New York, as Trustee, including form of
Notes.(h)
4.6.2 First Supplemental Indenture dated as of July 31, 2000
between the Company and The Bank of New York, as Trustee.(*)
4.7.1 Indenture dated as of August 10, 2000 between the Company
and Wilmington Trust Company, as Trustee.(m)
4.7.2 First Supplemental Indenture dated as of September 28, 2000
between the Company and Wilmington Trust Company, as
Trustee.(*)
4.8 Rights Agreement, dated as of June 5, 1997, between Calpine
Corporation and First Chicago Trust Company of New York, as
Rights Agent.(l)
4.9 HIGH TIDES I.
108
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.9.1 Certificate of Trust of Calpine Capital Trust, a Delaware
statutory trust, filed October 4, 1999.(i)
4.9.2 Corrected Certificate of Certificate of Trust of Calpine
Capital Trust, a Delaware statutory trust, dated September
29, 1999.(i)
4.9.3 Declaration of Trust of Calpine Capital Trust, dated as of
October 4, 1999, among Calpine Corporation, as Depositor,
The Bank of New York (Delaware), as Delaware Trustee, The
Bank of New York, as Property Trustee, and the
Administrative Trustees named therein.(i)
4.9.4 Indenture, dated as of November 2, 1999, between Calpine
Corporation and The Bank of New York, as Trustee, including
form of Debenture.(i)
4.9.5 Remarketing Agreement, dated November 2, 1999, among Calpine
Corporation, Calpine Capital Trust, The Bank of New York, as
Tender Agent, and Credit Suisse First Boston Corporation, as
Remarketing Agent.(i)
4.9.6 Amended and Restated Declaration of Trust of Calpine Capital
Trust, dated as of November 2, 1999, among Calpine
Corporation, as Depositor and Debenture Issuer, The Bank of
New York (Delaware), as Delaware Trustee, and The Bank of
New York, as Property Trustee, and the Administrative
Trustees named therein, including form of Preferred Security
and form of Common Security.(i)
4.9.7 Preferred Securities Guarantee Agreement, dated as of
November 2, 1999, between Calpine Corporation and The Bank
of New York, as Guarantee Trustee.(i)
4.10 HIGH TIDES II.
4.10.1 Certificate of Trust of Calpine Capital Trust II, a Delaware
statutory trust, filed January 25, 2000.(n)
4.10.2 Declaration of Trust of Calpine Capital Trust II, dated as
of January 24, 2000, among Calpine Corporation, as Depositor
and Debenture Issuer, The Bank of New York (Delaware), as
Delaware Trustee, The Bank of New York, as Property Trustee,
and the Administrative Trustees named therein.(n)
4.10.3 Indenture, dated as of January 31, 2000, between Calpine
Corporation and The Bank of New York, as Trustee, including
form of Debenture.(n)
4.10.4 Remarketing Agreement, dated as of January 31, 2000, among
Calpine Corporation, Calpine Capital Trust II, The Bank of
New York, as Tender Agent, and Credit Suisse First Boston
Corporation, as Remarketing Agent.(n)
4.10.5 Registration Rights Agreement, dated January 31, 2000, among
Calpine Corporation, Calpine Capital Trust II, Credit Suisse
First Boston Corporation and ING Barings LLC.(n)
4.10.6 Amended and Restated Declaration of Trust of Calpine Capital
Trust II, dated as of January 31, 2000, among Calpine
Corporation, as Depositor and Debenture Issuer, The Bank of
New York (Delaware), as Delaware Trustee, The Bank of New
York, as Property Trustee, and the Administrative Trustees
named therein, including form of Preferred Security and form
of Common Security.(n)
4.10.7 Preferred Securities Guarantee Agreement, dated as of
January 31, 2000, between Calpine Corporation and The Bank
of New York, as Guarantee Trustee.(n)
4.11 HIGH TIDES III.
4.11.1 Amended and Restated Certificate of Trust of Calpine Capital
Trust III, a Delaware statutory trust, filed July 19,
2000.(o)
4.11.2 Declaration of Trust of Calpine Capital Trust III dated June
28, 2000, among the Company, as Depositor and Debenture
Issuer, The Bank of New York (Delaware), as Delaware
Trustee, The Bank of New York, as Property Trustee and the
Administrative Trustees named therein.(o)
109
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.11.3 Amendment No. 1 to the Declaration of Trust of Calpine
Capital Trust III dated July 19, 2000, among the Company, as
Depositor and Debenture Issuer, Wilmington Trust Company, as
Delaware Trustee, Wilmington Trust Company, as Property
Trustee, and the Administrative Trustees named therein.(o)
4.11.4 Indenture dated as of August 9, 2000, between the Company
and Wilmington Trust Company, as Trustee.(o)
4.11.5 Remarketing Agreement dated as of August 9, 2000, among the
Company, Calpine Capital Trust III, Wilmington Trust
Company, as Tender Agent, and Credit Suisse First Boston
Corporation, as Remarketing Agent.(o)
4.11.6 Registration Rights Agreement dated as August 9, 2000,
between the Company, Calpine Capital Trust III, Credit
Suisse First Boston Corporation, ING Barings LLC and CIBC
World Markets Corp.(o)
4.11.7 Amended and Restated Declaration of Trust of Calpine Capital
Trust III dated as of August 9, 2000, the Company, as
Depositor and Debenture Issuer, Wilmington Trust Company, as
Delaware Trustee, Wilmington Trust Company, as Property
Trustee, and the Administrative Trustees named therein,
including the form of Preferred Security and form of Common
Security.(o)
4.11.8 Preferred Securities Guarantee Agreement dated as of August
9, 2000, between the Company, as Guarantor, and Wilmington
Trust Company, as Guarantee Trustee.(o)
4.12 PASS THROUGH CERTIFICATES.
4.12.1 Pass Through Trust Agreement dated as of December 19, 2000,
among Tiverton Power Associates Limited Partnership, Rumford
Power Associates Limited Partnership and State Street Bank
and Trust Company of Connecticut, National Association, as
Pass Through Trustee, including the form of Certificate.(*)
4.12.2 Participation Agreement dated as of December 19, 2000, among
the Company, Tiverton Power Associates Limited Partnership,
Rumford Power Associates Limited Partnership, PMCC Calpine
New England Investment LLC, PMCC Calpine NEIM LLC, State
Street Bank and Trust Company of Connecticut, National
Association, as Indenture Trustee, and State Street Bank and
Trust Company of Connecticut, National Association, as Pass
Through Trustee.(*)
4.12.3 Appendix A -- Definitions and Rules of Interpretation.(*)
4.12.4 Indenture of Trust, Mortgage and Security Agreement, dated
as of December 19, 2000, between PMCC Calpine New England
Investment LLC and State Street Bank and Trust Company of
Connecticut, National Association, as Indenture Trustee,
including the forms of Lessor Notes.(*)
4.12.5 Calpine Guaranty and Payment Agreement (Tiverton) dated as
of December 19, 2000, by Calpine, as Guarantor, to PMCC
Calpine New England Investment LLC, PMCC Calpine NEIM LLC,
State Street Bank and Trust Company of Connecticut, as
Indenture Trustee, and State Street Bank and Trust Company
of Connecticut, as Pass Through Trustee.(*)
4.12.6 Calpine Guaranty and Payment Agreement (Rumford) dated as of
December 19, 2000, by Calpine, as Guarantor, to PMCC Calpine
New England Investment LLC, PMCC Calpine NEIM LLC, State
Street Bank and Trust Company of Connecticut, as Indenture
Trustee, and State Street Bank and Trust Company of
Connecticut, as Pass Through Trustee.(*)
10.1 Purchase Agreements.
10.1.1 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.(f)
110
EXHIBIT
NUMBER DESCRIPTION
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10.1.2 Stock Purchase and Redemption Agreement dated March 31,
1998, among Dominion Cogen, Inc., Dominion Energy, Inc. and
Calpine Finance.(f)
10.2 Financing Agreements.
10.2.1 Calpine Construction Finance Company Financing Agreement
("CCFC I"), dated as of October 20, 1999.(j)
10.2.2 Calpine Construction Finance Company Financing Agreement
("CCFC II"), dated as of October 16, 2000.(p)(*)
10.2.3 Second Amended and Restated Credit Agreement dated as of May
23, 2000, among the Company, Bayerische Landesbank, as
Co-Arranger and Syndication Agent, The Bank of Nova Scotia,
as Lead Arranger and Administrative Agent, and the Lenders
named therein.(m)
10.3 Other Agreements.
10.3.1 Calpine Corporation Stock Option Program and forms of
agreements there under.(a)
10.3.2 Calpine Corporation 1996 Stock Incentive Plan and forms of
agreements there under.(b)
10.3.3 Calpine Corporation Employee Stock Purchase Plan and forms
of agreements there under.(b)
10.3.4 Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright.(b)
10.3.5 Executive Vice President Employment Agreement between
Calpine Corporation and Ms. Ann B. Curtis.(k)
10.3.6 Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Ron A. Walter.(k)
10.3.7 Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Robert D. Kelly.(k)
10.3.8 Executive Vice President Employment Agreement between
Calpine Corporation and Mr. Thomas R. Mason.(k)
10.4 Form of Indemnification Agreement for directors and
officers.(b)
12.1 Statement on Computation of Ratio of Earnings to Fixed
Charges.(*)
21 Subsidiaries of the Company.(*)
23.1 Consent of Arthur Andersen LLP, Independent Public
Accountants.(*)
23.2 Consent of Netherland, Sewell & Associates, Inc.,
independent engineer.(*)
23.3 Consent of McDaniel & Associates Consultants, Ltd.,
independent engineer.(*)
23.4 Consent of Gilbert Laustsen Jung Associates, Ltd.,
independent engineer.(*)
24 Power of Attorney of Officers and Directors of Calpine
Corporation (set forth on the signature pages of this
report).(*)
- ---------------
(a) Incorporated by reference to Registrant's Registration Statement on Form S-1
(Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Registration Statement on Form
S-1/A (Registration Statement No. 333-07497).
(c) Incorporated by reference to Registrant's Registration Statement on Form S-4
(Registration Statement No. 333-06259.
(d) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1996 and filed on May 14, 1996.
(e) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1997 and filed on August 14, 1997.
111
(f) Incorporated by reference to Registrant's Current Report on Form 8-K dated
March 31, 1998 and filed on April 14, 1998.
(g) Incorporated by reference to Registrant's Registration Statement on Form S-4
(Registration Statement No. 333-61047).
(h) Incorporated by reference to Registrant's Registration Statement on Form
S-3/A (Registration Statement No. 333-72583).
(i) Incorporated by reference to Registrant's Registration Statement on Form
S-3/A (Registration Statement No. 333-87427).
(j) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1999 and filed on February 29, 2000. Approximately 200 pages of
this exhibit have been omitted pursuant to a request for confidential
treatment. The omitted language has been filed separately with the
Securities and Exchange Commission.
(k) Incorporated by reference to Registrant's Form 10-Q/A dated September 30,
1999 and filed on November 17, 1999.
(l) Incorporated by reference to Registrant's Registration Statement on Form
8-A, amended by Calpine's Registration Statement on Form 8-A/A (Registration
Statement No. 001-12079).
(m) Incorporated by reference to Registrant's Current Report on Form 8-K dated
July 25, 2000 and filed on August 9, 2000.
(n) Incorporated by reference to Registrant's Registration Statement on Form S-3
(Registration Statement No. 333-33736).
(o) Incorporated by reference to Registrant's Registration Statement on Form S-3
(Registration Statement No. 333-47068).
(p) Approximately 71 pages of tis exhibit have been omitted pursuant to a
request for confidential treatment. The omitted language has been filed
separately with the Securities and Exchange Commission.
(q) Incorporated by reference to Registrant's Registration Statement on Form S-4
(Registration Statement No. 333-41261).
(*) Filed herewith.