-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, HGKMG3MMnvN3frBpfWLOZKR+s7WpyvOtftpbKdgzh9GgrPv8AzvyfP1nI4Q3N2Hx y4kBynua+7ST/4Kvxjh/Ng== 0000891618-99-004219.txt : 19990921 0000891618-99-004219.hdr.sgml : 19990921 ACCESSION NUMBER: 0000891618-99-004219 CONFORMED SUBMISSION TYPE: S-3 PUBLIC DOCUMENT COUNT: 3 FILED AS OF DATE: 19990920 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CALPINE CORP CENTRAL INDEX KEY: 0000916457 STANDARD INDUSTRIAL CLASSIFICATION: COGENERATION SERVICES & SMALL POWER PRODUCERS [4991] IRS NUMBER: 770212977 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: S-3 SEC ACT: SEC FILE NUMBER: 333-87427 FILM NUMBER: 99714102 BUSINESS ADDRESS: STREET 1: 50 WEST SAN FERNANDO ST CITY: SAN JOSE STATE: CA ZIP: 95113 BUSINESS PHONE: 4089955115 MAIL ADDRESS: STREET 1: 50 W SAN FERNANDO STREET 2: SUITE 500 CITY: SAN JOSE STATE: CA ZIP: 95113 S-3 1 FORM S-3 1 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON SEPTEMBER 20, 1999 REGISTRATION NO. 333- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------ FORM S-3 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 CALPINE CORPORATION (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 4911 77-0212977 (STATE OF INCORPORATION) (PRIMARY STANDARD INDUSTRIAL (I.R.S. EMPLOYER CLASSIFICATION CODE NUMBER) IDENTIFICATION NO.)
50 WEST SAN FERNANDO STREET SAN JOSE, CA 95113 (408) 995-5115 (ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE, OF REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES) ------------------------ PETER CARTWRIGHT CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER CALPINE CORPORATION 50 WEST SAN FERNANDO STREET SAN JOSE, CA 95113 (408) 995-5115 (NAME, ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE, OF AGENT FOR SERVICE) ------------------------ COPIES TO: J. MICHAEL SHEPHERD, ESQ. JOSEPH A. COCO, ESQ. NORA L. GIBSON, ESQ. SKADDEN, ARPS, SLATE, MEAGHER & FLOM LLP BROBECK, PHLEGER & HARRISON LLP 919 THIRD AVENUE ONE MARKET NEW YORK, NY 10022-3897 SPEAR STREET TOWER (212) 735-3000 SAN FRANCISCO, CA 94105 (415) 442-0900
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after this Registration Statement becomes effective. If the only securities being registered on this Form are being offered pursuant to dividend or interest reinvestment plans, please check the following box. [ ] If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, other than securities offered only in connection with dividend or interest reinvestment plans, check the following box. [ ] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [ ] - ------------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------------- TITLE OF EACH CLASS AMOUNT PROPOSED MAXIMUM PROPOSED MAXIMUM OF SECURITIES TO BE TO BE OFFERING PRICE AGGREGATE OFFERING AMOUNT OF REGISTERED REGISTERED(1) PER SECURITY(2) PRICE(2) REGISTRATION FEE - ------------------------------------------------------------------------------------------------------------------------- Common Stock......................... 6,900,000 $45.094 $311,148,600 $86,499 - ------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------
(1) Includes 900,000 shares of common stock as to which the underwriters have been granted an option to cover over-allotments, if any. (2) The proposed maximum offering price per share and the registration fee were calculated in accordance with Rule 457(c) based on the average of the high and low prices for the registrant's common stock on September 15, 1999, as listed on the New York Stock Exchange, and adjusted to reflect the registrant's 2 for 1 stock split declared on September 20, 1999. THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT THAT SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES EXCHANGE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 2 THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES AND IS NOT SOLICITING AN OFFER TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED. SUBJECT TO COMPLETION DATED SEPTEMBER 20, 1999 6,000,000 Shares LOGO CALPINE CORPORATION Common Stock ------------------ Our common stock is listed on The New York Stock Exchange under the symbol "CPN." On September , 1999, the last sale price of the common stock was $ . The underwriters have an option to purchase a maximum of 900,000 additional shares to cover over-allotments of shares. Concurrently with this offering, we are offering $200 million of convertible preferred securities of a subsidiary trust by means of a separate prospectus. This offering and the convertible trust preferred securities offering are not contingent on each other. INVESTING IN OUR COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE 8.
UNDERWRITING PROCEEDS TO PRICE TO DISCOUNTS AND CALPINE PUBLIC COMMISSIONS CORPORATION -------------- -------------- -------------- Per Share............................................ $ $ $ Total................................................ $ $ $
Delivery of the shares of common stock will be made on or about , 1999. Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. CREDIT SUISSE FIRST BOSTON The date of this prospectus is , 1999. 3 [Depiction of Delta Energy Center.] "Delta Energy Center, a proposed 880 megawatt gas-fired facility located in Pittsburg, California." [Depiction of Pasadena Power Plant.] "Pasadena Power Plant, a 240 megawatt gas-fired facility located in Pasadena, Texas." 4 ------------------ TABLE OF CONTENTS
Page ---- PROSPECTUS SUMMARY.................. 1 RISK FACTORS........................ 8 WHERE YOU CAN FIND MORE INFORMATION....................... 17 FORWARD-LOOKING STATEMENTS.......... 18 USE OF PROCEEDS..................... 19 PRICE RANGE OF COMMON STOCK......... 20 DIVIDEND POLICY..................... 20 CAPITALIZATION...................... 21 SELECTED CONSOLIDATED FINANCIAL DATA.............................. 22 PRO FORMA CONSOLIDATED FINANCIAL DATA.............................. 24
Page ---- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS..................... 26 BUSINESS............................ 42 MANAGEMENT.......................... 68 PRINCIPAL STOCKHOLDERS.............. 71 DESCRIPTION OF CAPITAL STOCK........ 73 UNDERWRITING........................ 75 NOTICE TO CANADIAN RESIDENTS........ 76 LEGAL MATTERS....................... 78 EXPERTS............................. 78
------------------ YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS DOCUMENT OR TO WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH INFORMATION THAT IS DIFFERENT. THIS DOCUMENT MAY ONLY BE USED WHERE IT IS LEGAL TO SELL THESE SECURITIES. THE INFORMATION CONTAINED IN THIS DOCUMENT MAY ONLY BE ACCURATE ON THE DATE OF THIS DOCUMENT. i 5 PROSPECTUS SUMMARY This summary highlights information contained elsewhere in this prospectus. This summary is not complete and does not contain all of the information that you should consider before investing in the common stock. You should carefully read the entire prospectus, including the risk factors, the financial statements and the documents incorporated by reference into it. The terms "Calpine," "our company," "our" and "we," as used in this prospectus, refer to Calpine Corporation and its consolidated subsidiaries. All information in this prospectus reflects the 2 for 1 stock split declared by us on September 20, 1999. THE COMPANY 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 37 power plants having an aggregate capacity of 3,627 megawatts and have a transaction pending in which we will acquire 80% of Cogeneration Corporation of America, which owns interests in 6 power plants with an aggregate capacity of 579 megawatts. We also have 6 gas-fired projects and one project expansion under construction having an aggregate capacity of 3,440 megawatts and have announced plans to develop 6 gas-fired power plants with a total capacity of 3,665 megawatts. Upon completion of pending acquisitions and projects under construction, we will have interests in 49 power plants located in 14 states having an aggregate capacity of 7,646 megawatts, of which we will have a net interest in 6,541 megawatts. This represents significant growth from the 342 megawatts of capacity we had at the end of 1993. Of this total generating capacity, 89% will be attributable to gas-fired facilities and 11% will be attributable to geothermal facilities. As a result of our expansion program, our revenues, cash flow, earnings and assets have grown significantly over the last five years, as shown in the table below.
COMPOUND ANNUAL 1993 1998 GROWTH RATE -------- ---------- --------------- (DOLLARS IN MILLIONS) Total Revenue....................... $ 69.9 $ 555.9 51% EBITDA.............................. 42.4 255.3 43% Net Income.......................... 3.8 45.7 64% Total Assets........................ 302.3 1,728.9 42%
Since our inception in 1984, we have developed substantial expertise in all aspects of the development, acquisition and operation of power generation facilities. We believe that the vertical integration of our extensive engineering, construction management, operations, fuel management and financing capabilities provides us with a competitive advantage to successfully implement our acquisition and development program and has contributed to our significant growth over the past five years. 1 6 THE MARKET The power industry represents the third largest industry in the United States, with an estimated end-user market of over $250 billion of electricity sales in 1998 produced by an aggregate base of power generation facilities with a capacity of approximately 750,000 megawatts. In response to increasing customer demand for access to low-cost electricity and enhanced services, new regulatory initiatives have been and are continuing to be adopted at both the state and federal level to increase competition in the domestic power generation industry. The power generation industry historically has been largely characterized by electric utility monopolies producing electricity from old, inefficient, high-cost generating facilities selling to a captive customer base. Industry trends and regulatory initiatives have transformed the existing market into a more competitive market where end users purchase electricity from a variety of suppliers, including non-utility generators, power marketers, public utilities and others. There is a significant need for additional power generating capacity throughout the United States, both to satisfy increasing demand, as well as to replace old and inefficient generating facilities. Due to environmental and economic considerations, we believe this new capacity will be provided predominantly by gas-fired facilities. We believe that these market trends will create substantial opportunities for efficient, low-cost power producers that can produce and sell energy to customers at competitive rates. In addition, as a result of a variety of factors, including deregulation of the power generation market, utilities, independent power producers and industrial companies are disposing of power generation facilities. To date, numerous utilities have sold or announced their intentions to sell their power generation facilities and have focused their resources on the transmission and distribution 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 proven growth strategy, we utilize our extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach uses our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations and power marketing, which we believe provides us with a competitive advantage. The key elements of our strategy are as follows: - Development and expansion of power plants. We are actively pursuing the development and expansion of highly efficient, low-cost, gas-fired power plants to replace old and inefficient generating facilities and meet the demand for new generation. - 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. 2 7 - 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. RECENT DEVELOPMENTS Project Development and Construction. In May 1999, we completed a 35 megawatt expansion of our Clear Lake Power Plant to 412 megawatts, and the 169 megawatt Dighton Power Plant commenced commercial operations in August 1999. We currently have seven projects under construction representing 3,440 additional megawatts. Of these new projects, we are currently expanding our Pasadena facility by 545 megawatts to 785 megawatts and we have six new power plants under construction, including the Tiverton Power Plant in Rhode Island; the Rumford Power Plant in Maine; the Westbrook Power Plant in Maine; the Sutter Power Plant in California; the South Point Power Plant in Arizona; and the Magic Valley Power Plant in Texas. We have also announced plans to develop six additional power generation facilities, totaling 3,665 megawatts, in California, Texas, Arizona and Pennsylvania. In July 1999, we announced an agreement with Credit Suisse First Boston, New York branch and The Bank of Nova Scotia, as lead arrangers, for a $1.0 billion revolving construction loan facility. The credit facility will be utilized to finance the construction of our development program. We expect to finalize the documentation relating to this facility in the third quarter of 1999. In August 1999, we announced the purchase of 18 F-class combustion turbines from Siemens Westinghouse Power Corporation that will be capable of producing 4,900 megawatts of electricity in a combined-cycle configuration. Beginning in 2002, Siemens will deliver six turbines per year through 2004. Combined with our existing turbine orders we have 69 turbines under contract, option or letter of intent capable of producing 17,745 megawatts. Acquisitions. In March 1999, we completed the acquisition of Unocal Corporation's Geysers geothermal steam fields in northern California for approximately $102.1 million. The steam fields fuel our 12 Sonoma County power plants, totaling 544 megawatts, purchased from Pacific Gas and Electric Company in May 1999. In May 1999 we completed the acquisition from Pacific Gas and Electric Company of 14 geothermal power plants at The Geysers in northern California, with a combined capacity of approximately 700 megawatts, for $212.8 million. With the acquisition, we now own interests in and operate 18 geothermal power plants that generate more than 800 megawatts of electricity, and we are the nation's largest geothermal and green power producer. The combination of our existing geothermal steam and power plant assets, the acquisition of the Sonoma steam fields from Unocal, and the 14 power plants from Pacific Gas and Electric Company allows us to fully integrate the steam and power plant operations at The Geysers into one efficient, unified system to maximize the renewable natural resource, lower overall production costs and extend the life of The Geysers. In August 1999, we completed the acquisition of an additional 50% of the Aidlin Power Plant from Edison Mission Energy (5%) and General Electric Capital Corporation (45%) for a total purchase price of $7.2 million. We now own 55% of the 20 megawatt Aidlin Geothermal Power Plant. 3 8 In August 1999, we announced an agreement with Sheridan Energy, Inc., a natural gas exploration and production company, to acquire Sheridan through a $41.0 million cash tender offer. We have offered to purchase all outstanding shares of Sheridan Energy's common stock for $5.50 per share. In addition, we have agreed to redeem $11.5 million of outstanding preferred stock of Sheridan Energy. We expect to complete the tender in October 1999. Sheridan Energy's oil and gas properties, including 148 billion cubic feet equivalent of proven reserves, are located in northern California and the Gulf Coast region, where we are developing low-cost natural gas supplies and proprietary pipeline systems to support our strategically-located natural gas-fired power plants. In August 1999, we announced an agreement with Cogeneration Corporation of America Inc. ("CGCA") to acquire 80% of its common stock for $25.00 per share or approximately $145.0 million. NRG Energy, Inc., a wholly owned subsidiary of Northern States Power, will own the remaining 20%. The transaction is subject to the approval of CGCA shareholders and we expect to consummate the acquisition by year-end 1999. CGCA currently owns interests in six natural gas-fired power plants, totaling 579 megawatts. The plants are located in Pennsylvania, New Jersey, Illinois and Oklahoma. Enhancement of Existing Power Plants. In July 1999, we announced a renegotiation of our Gilroy power sales agreement with Pacific Gas and Electric Company. The amendment provides for the termination of the remaining 18 years of the long-term contract in exchange for a fixed long-term payment schedule. The amended agreement is subject to approval by the California Public Utilities Commission, whose decision we expect to receive in the fourth quarter of 1999. We will continue to sell the output from the Gilroy Power Plant through October 2002 to Pacific Gas and Electric Company and thereafter we will market the output in the California wholesale power market. Our principal executive office is located at 50 West San Fernando Street, San Jose, CA 95113. Our telephone number is (408) 995-5115. 4 9 THE OFFERING Common stock offered by Calpine......................... 6,000,000 shares(1) Common stock to be outstanding after the offering............ 60,569,788 shares(1)(2) Convertible preferred offering........................ Concurrently with the common stock offering, our subsidiary trust is offering (by a separate prospectus) $200.0 million of convertible preferred securities. Use of proceeds................. We expect to use a substantial portion of the net proceeds from the offerings to finance power projects under development and construction. In addition, we expect to use $145.0 million of the net proceeds to complete the acquisition of 80% of CGCA and $53.0 million to complete the acquisition of Sheridan Energy. The remaining net proceeds, if any, will be used for working capital and general corporate purposes. New York Stock Exchange symbol.......................... CPN - ------------------------- (1) Excludes the 900,000 shares that may be issued pursuant to the underwriters' over-allotment option. (2) Based on 54,569,788 shares outstanding as of September 20, 1999. Does not include 3,453,458 shares of common stock subject to issuance upon exercise of options previously granted and outstanding as of August 31, 1999, under our 1996 Stock Incentive Plan. 5 10 SUMMARY CONSOLIDATED HISTORICAL FINANCIAL AND OPERATING INFORMATION The following table sets forth a summary of our consolidated historical financial and operating information for the periods indicated. Our summary consolidated historical financial information was derived from our consolidated financial statements. The information presented below should be read in conjunction with "Selected Consolidated Financial Data" and our consolidated financial statements and the related notes, incorporated by reference in this prospectus.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------------------------------------------ ----------------------- 1994 1995 1996 1997 1998 1998 1999 -------- ---------- ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) (UNAUDITED) STATEMENT OF OPERATIONS DATA: Total revenue.................. $ 94,762 $ 132,098 $ 214,554 $ 276,321 $ 555,948 $ 196,742 $ 336,590 Cost of revenue................ 52,845 77,388 129,200 153,308 375,327 136,125 238,170 Gross profit................... 41,917 54,710 85,354 123,013 180,621 60,617 98,420 Project development expenses... 1,784 3,087 3,867 7,537 7,165 3,119 4,248 General and administrative expenses..................... 7,323 8,937 14,696 18,289 26,780 11,043 20,964 Income from operations......... 31,772 42,686 66,791 97,187 146,676 46,455 73,208 Interest expense............... 23,886 32,154 45,294 61,466 86,726 40,790 47,171 Other (income) expense......... (1,988) (1,895) (6,259) (17,438) (13,423) (6,599) (11,068) Extraordinary charge net of tax benefit of $--, $--, $--, $--, $441, $207 and $793..... -- -- -- -- 641 302 1,150 Net income..................... $ 6,021 $ 7,378 $ 18,692 $ 34,699 $ 45,678 $ 8,569 $ 21,410 Diluted earnings per common share: Weighted average shares of common stock outstanding... 21,842 21,913 29,758 42,032 42,328 42,100 50,469 Income before extraordinary charge..................... $ 0.28 $ 0.34 $ 0.63 $ 0.83 $ 1.10 $ 0.21 $ 0.45 Extraordinary charge......... $ -- $ -- $ -- $ -- $ (0.02) $ (0.01) $ (0.02) Net income................... $ 0.28 $ 0.34 $ 0.63 $ 0.83 $ 1.08 $ 0.20 $ 0.43 OTHER FINANCIAL DATA AND RATIOS: Depreciation and amortization................. $ 21,580 $ 26,896 $ 40,551 $ 48,935 $ 82,913 $ 32,104 $ 45,449 EBITDA(1)...................... $ 53,707 $ 69,515 $ 117,379 $ 172,616 $ 255,306 $ 93,374 $ 151,927 EBITDA to Consolidated Interest Expense(2)................... 2.23x 2.11x 2.41x 2.60x 2.74x 2.16x 2.92x Total debt to EBITDA........... 6.23x 5.87x 5.12x 4.96x 4.20x -- -- Ratio of earnings to fixed charges(3)................... 1.52x 1.46x 1.45x 1.64x 1.68x 1.11x 1.43x SELECTED OPERATING INFORMATION: Power plants: Electricity revenue(4): Energy..................... $ 45,912 $ 54,886 $ 93,851 $ 110,879 $ 252,178 $ 93,735 $ 177,305 Capacity................... $ 7,967 $ 30,485 $ 65,064 $ 84,296 $ 193,535 $ 67,103 $ 106,155 Megawatt hours produced...... 447,177 1,033,566 1,985,404 2,158,008 9,864,080 2,217,659 5,516,805 Average energy price per kilowatt hour(5)........... 10.267c 5.310c 4.727c 5.138c 2.557c 4.227c 3.214c
Footnotes appear on the next page. 6 11
AS OF DECEMBER 31, AS OF ------------------------------------------------------------ JUNE 30, 1994 1995 1996 1997 1998 1999 -------- ---------- ---------- ---------- ---------- ----------- (DOLLARS IN THOUSANDS) (UNAUDITED) BALANCE SHEET DATA: Cash and cash equivalents........... $ 22,527 $ 21,810 $ 95,970 $ 48,513 $ 96,532 $ 320,287 Total assets............ 421,372 554,531 1,031,397 1,380,915 1,728,946 2,549,750 Short-term debt......... 27,300 85,885 37,492 112,966 5,450 -- Long-term line of credit................ -- 19,851 -- -- -- -- Long-term non-recourse debt.................. 196,806 190,642 278,640 182,893 114,190 79,210 Notes payable........... 5,296 6,348 -- -- -- -- Senior notes............ 105,000 105,000 285,000 560,000 951,750 1,551,750 Total debt.............. 334,402 407,726 601,132 855,859 1,071,390 1,630,960 Stockholders' equity.... 18,649 25,227 203,127 239,956 286,966 514,127
- ------------------------- (1) EBITDA is defined as income from operations plus depreciation, capitalized interest, other income, non-cash charges and cash received from investments in power projects, reduced by the income from unconsolidated investments in power projects. EBITDA is presented not as a measure of operating results but rather as a measure of our ability to service debt. EBITDA should not be construed as an alternative either (a) to income from operations (determined in accordance with generally accepted accounting principles) or (b) to cash flows from operating activities (determined in accordance with generally accepted accounting principles). (2) For purposes of calculating the EBITDA to Consolidated Interest Expense ratio, Consolidated Interest Expense is defined as total interest expense plus one-third of all operating lease obligations, dividends paid in respect of preferred stock and cash contributions to any employee stock ownership plan used to pay interest on loans incurred to purchase our capital stock. (3) Earnings are defined as income before provision for taxes, extraordinary item and cumulative effect of changes in accounting principle plus cash received from investments in power projects and fixed charges reduced by the equity in income from investments in power projects and capitalized interest. Fixed charges consist of interest expense, capitalized interest, amortization of debt issuance costs and the portion of rental expenses representative of the interest expense component. (4) Electricity revenue is comprised of fixed capacity payments, which are not related to production volume, and variable energy payments, which are related to production volume. (5) The average energy price per kilowatt hour represents energy revenue divided by the megawatt hours produced. 7 12 RISK FACTORS You should carefully consider the risks described below before making an investment decision. The risks and uncertainties described below are not the only ones facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations. Each of the following factors could have a material adverse effect on our business, financial condition or results of operations, causing the trading price of our common stock to decline and the loss of all or part of your investment. 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 June 30, 1999, our total consolidated indebtedness was $1.6 billion, our total consolidated assets were $2.5 billion and our stockholders' equity was $514.1 million. On June 30, 1999, on an as adjusted basis after giving effect to the sale of common stock and convertible preferred securities in the offerings and the application of the proceeds from the offerings, our total consolidated indebtedness would have been approximately $1.6 billion, our total consolidated assets would have been approximately $3.0 billion and our as adjusted cash balances would have been approximately $777.2 million. Whether we will be able to meet our debt service obligations and to repay our outstanding indebtedness will be dependent primarily upon the performance of our power generation facilities. This high level of indebtedness has important consequences, including: - limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our growth strategy, or other purposes, - limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt, - increasing our vulnerability to general adverse economic and industry conditions, and - limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in government regulation. The operating and financial restrictions and covenants in our existing debt agreements, including the indentures relating to our $1.5 billion aggregate principle amount of senior notes and our $100.0 million revolving credit facility, contain restrictive covenants. Among other things, these restrictions limit or prohibit our ability to: - incur indebtedness, - make prepayments of indebtedness in whole or in part, - pay dividends, - make investments, - engage in transactions with affiliates, - create liens, - sell assets, and - acquire facilities or other businesses. 8 13 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 non-recourse project financing agreements of certain of our subsidiaries and other affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to us prior to the payment of other obligations, including operating expenses, debt service and reserves. Our subsidiaries and other affiliates are separate and distinct legal entities and have no obligation to pay any amounts due on our senior notes, and do not guarantee the payment of interest on or principal of these notes. The right of our senior note holders to receive any assets of any of our subsidiaries or other affiliates upon our liquidation or reorganization will be subordinated to the claims of any subsidiaries' or other affiliates' creditors (including trade creditors and holders of debt issued by our subsidiaries or affiliates). As of June 30, 1999, our subsidiaries had $79.2 million of non-recourse project financing. We intend to utilize non-recourse project financing in the future that 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 non-recourse project financing that our subsidiaries may incur to finance the acquisition and development of new power generation facilities. 9 14 WE MAY BE UNABLE TO SECURE ADDITIONAL FINANCING IN THE FUTURE Each power generation facility that we acquire or develop will require substantial capital investment. Our ability to arrange financing and the cost of the financing are dependent upon numerous factors. These factors include: - general economic and capital market conditions, - conditions in energy markets, - regulatory developments, - credit availability from banks or other lenders, - investor confidence in the industry and in us, - the continued success of our current power generation facilities, and - provisions of tax and securities laws that are conducive to raising capital. Financing for new facilities may not be available to us on acceptable terms in the future. We have financed our existing power generation facilities using a variety of leveraged financing structures, primarily consisting of non-recourse project financing and lease obligations. As of June 30, 1999, we had approximately $1.6 billion of total consolidated indebtedness, $79.2 million of which represented non-recourse project financing. Each non-recourse project financing and lease obligation is structured to be fully paid out of cash flow provided by the facility or facilities. In the event of a default under a financing agreement which we do not cure, the lenders or lessors would generally have rights to the facility and any related assets. In the event of foreclosure after a default, we might not retain any interest in the facility. While we intend to utilize non-recourse or lease financing when appropriate, market conditions and other factors may prevent similar financing for future facilities. We do not believe the existence of non-recourse or lease financing will significantly affect our ability to continue to borrow funds in the future in order to finance new facilities. However, it is possible that we may be unable to obtain the financing required to develop our power generation facilities on terms satisfactory to us. We have from time to time guaranteed certain obligations of our subsidiaries and other affiliates. Our lenders or lessors may also require us to guarantee the indebtedness for future facilities. This would render our general corporate funds vulnerable in the event of a default by the facility or related subsidiary. Additionally, our indentures may restrict our ability to guarantee future debt, which could adversely affect our ability to fund new facilities. Our indentures do not limit the ability of our subsidiaries to incur non-recourse or lease financing for investment in new facilities. REVENUE UNDER SOME OF OUR POWER SALES AGREEMENTS MAY BE REDUCED SIGNIFICANTLY UPON THEIR EXPIRATION OR TERMINATION Most of the electricity we generate from our existing portfolio is sold under long-term power sales agreements that expire at various times. When the terms of each of these power sales agreements expire, it is possible that the price paid to us for the generation of electricity may be reduced significantly, which would substantially reduce our revenue under such agreements. The fixed price periods in some of our long-term power sales agreements have recently expired, and the electricity under those agreements is now sold at 10 15 a fluctuating market price. For example, the price for electricity for two of our power plants, the Bear Canyon (20 megawatts) and West Ford Flat (27 megawatts) power plants, was approximately 13.83 cents per kilowatt hour under the fixed price periods that recently expired for these facilities, and is now set at the energy clearing price, which averaged 2.66 cents per kilowatt hour during 1998. As a result, our energy revenue under these power sales agreements has been materially reduced. We expect the decline in energy revenues will be partially mitigated by decreased royalties and planned operating cost reductions at these facilities. In addition, we will continue our strategy of offsetting these reductions through our acquisition and development program. OUR POWER PROJECT DEVELOPMENT AND ACQUISITION ACTIVITIES MAY NOT BE SUCCESSFUL The development of power generation facilities is subject to substantial risks. In connection with the development of a power generation facility, we must generally obtain: - necessary power generation equipment, - governmental permits and approvals, - fuel supply and transportation agreements, - sufficient equity capital and debt financing, - electrical transmission agreements, and - site agreements and construction contracts. We may be unsuccessful in accomplishing any of these matters or in doing so on a timely basis. In addition, project development is subject to various environmental, engineering and construction risks relating 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. 11 16 OUR PROJECTS UNDER CONSTRUCTION MAY NOT COMMENCE OPERATION AS SCHEDULED The commencement of operation of a newly constructed power generation facility involves many risks, including: - start-up problems, - the breakdown or failure of equipment or processes, and - performance below expected levels of output or efficiency. New plants have no operating history and may employ recently developed and technologically complex equipment. Insurance is maintained to protect against certain risks, warranties are generally obtained for limited periods relating to the construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. The insurance, warranties or performance guarantees, however, may not be adequate to cover lost revenues or increased expenses. As a result, a project may be unable to fund principal and interest payments under its financing obligations and may operate at a loss. A default under such a financing obligation could result in losing our interest in a power generation facility. In addition, power sales agreements entered into with a utility early in the development phase of a project may enable the utility to terminate the agreement, or to retain security posted as liquidated damages, if a project fails to achieve commercial operation or certain operating levels by specified dates or fails to make specified payments. In the event a termination right is exercised, the default provisions in a financing agreement may be triggered (rendering such debt immediately due and payable). As a result, the project may be rendered insolvent and we may lose our interest in the project. OUR POWER GENERATION FACILITIES MAY NOT OPERATE AS PLANNED Upon completion of our pending acquisitions and projects currently under construction, we will operate 39 of the 49 power plants in which we will have an interest. The continued operation of power generation facilities involves many risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes and performance below expected levels of output or efficiency. Although from time to time our power generation facilities have experienced equipment breakdowns or failures, these breakdowns or failures have not had a significant effect on the operation of the facilities or on our results of operations. As of June 30, 1999, our gas- fired and geothermal power generation facilities have operated at an average availability of approximately 96% and 99%, 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. 12 17 OUR GEOTHERMAL ENERGY RESERVES MAY BE INADEQUATE FOR OUR OPERATIONS The development and operation of geothermal energy resources are subject to substantial risks and uncertainties similar to those experienced in the development of oil and gas resources. The successful exploitation of a geothermal energy resource ultimately depends upon: - the heat content of the extractable fluids, - the geology of the reservoir, - the total amount of recoverable reserves, - operating expenses relating to the extraction of fluids, - price levels relating to the extraction of fluids, and - capital expenditure requirements relating primarily to the drilling of new wells. In connection with each geothermal power plant, we estimate the productivity of the geothermal resource and the expected decline in productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the electrical power capacity desired. An incorrect estimate by us or an unexpected decline in productivity could lower our results of operations. Geothermal reservoirs are highly complex. As a result, there exist numerous uncertainties in determining the extent of the reservoirs and the quantity and productivity of the steam reserves. Reservoir engineering is an inexact process of estimating underground accumulations of steam or fluids that cannot be measured in any precise way, and depends significantly on the quantity and accuracy of available data. As a result, the estimates of other reservoir specialists may differ materially from ours. Estimates of reserves are generally revised over time on the basis of the results of drilling, testing and production that occur after the original estimate was prepared. While we have extensive experience in the operation and development of geothermal energy resources and in preparing such estimates, we cannot assure you that we will be able to successfully manage the development and operation of our geothermal reservoirs or that we will accurately estimate the quantity or productivity of our steam reserves. WE DEPEND ON OUR ELECTRICITY AND THERMAL ENERGY CUSTOMERS Each of our power generation facilities currently relies on one or more power sales agreements with one or more utility or other customers for all or substantially all of such facility's revenue. In addition, the sales of electricity to two utility customers during 1998 comprised approximately 64% of our total revenue during that year. The loss of any one power sales agreement with any of these customers could have a negative effect on our results of operations. In addition, any material failure by any customer to fulfill its obligations under a power sales agreement could have a negative effect on the cash flow available to us and on our results of operations. 13 18 WE ARE SUBJECT TO COMPLEX GOVERNMENT REGULATION WHICH COULD ADVERSELY AFFECT OUR OPERATIONS Our activities are subject to complex and stringent energy, environmental and other governmental laws and regulations. The construction and operation of power generation facilities require numerous permits, approvals and certificates from appropriate federal, state and local governmental agencies, as well as compliance with environmental protection legislation and other regulations. While we believe that we have obtained the requisite approvals for our existing operations and that our business is operated in accordance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. Existing laws and regulations may be revised or new laws and regulations may become applicable to us that may have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed facilities may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain permits. If a project is unable to function as planned due to changing requirements or local opposition, it may create expensive delays or significant loss of value in a project. Our operations are potentially subject to the provisions of various energy laws and regulations, including the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1955, as amended ("PUHCA"), and state and local regulations. PUHCA provides for the extensive regulation of public utility holding companies and their subsidiaries. PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and owners of QFs certain exemptions from certain federal and state regulations, including rate and financial regulations. Under present federal law, we are not subject to regulation as a holding company under PUHCA, and will not be subject to such regulation as long as the plants in which we have an interest (1) qualify as QFs, (2) are subject to another exemption or waiver or (3) qualify as exempt wholesale generators ("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility must be not more than 50% owned by an electric utility company or electric utility holding company. In addition, a QF that is a cogeneration facility, such as the plants in which we currently have interests, must produce electricity as well as thermal energy for use in an industrial or commercial process in specified minimum proportions. The QF also must meet certain minimum energy efficiency standards. Any geothermal power facility which produces up to 80 megawatts of electricity and meets PURPA ownership requirements is considered a QF. If any of the plants in which we have an interest lose their QF status or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded QFs, we could become a public utility holding company, which could subject us to significant federal, state and local regulation, including rate regulation. If we become a holding company, which could be deemed to occur prospectively or retroactively to the date that any of our plants loses its QF status, all our other power plants could lose QF status because, under 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 14 19 of some or all contract revenues or otherwise impair the value of a project. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Such events could adversely affect our ability to service our indebtedness, including our senior notes. See "Business -- Government Regulation -- Federal Energy Regulation." Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at prices based on avoided costs of energy. We do not know whether this legislation will be passed or, if passed, what form it may take. We cannot provide assurance that any legislation passed would not adversely affect our existing domestic projects. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry and increase access to electric utilities' transmission and distribution systems for independent power producers and electricity consumers. In particular, the state of California has restructured its electric industry by providing for a phased-in competitive power generation industry, with a power pool and an independent system operator, and for direct access to generation for all power purchasers outside the power exchange under certain circumstances. Although existing QF power sales contracts are to be honored under such restructuring, and all of our California operating projects are QFs, until the new system is fully implemented, it is impossible to predict what impact, if any, it may have on the operations of those projects. WE MAY BE UNABLE TO OBTAIN AN ADEQUATE SUPPLY OF NATURAL GAS IN THE FUTURE To date, our fuel acquisition strategy has included various combinations of our own gas reserves, gas prepayment contracts and short-, medium- and long-term supply contracts. In our gas supply arrangements, we attempt to match the fuel cost with the fuel component included in the facility's power sales agreements in order to minimize a project's exposure to fuel price risk. We believe that there will be adequate supplies of natural gas available at reasonable prices for each of our facilities when current gas supply agreements expire. However, gas supplies may not be available for the full term of the facilities' power sales agreements, and gas prices may increase significantly. If gas is not available, or if gas prices increase above the fuel component of the facilities' power sales agreements, there could be a negative impact on our results of operations. COMPETITION COULD ADVERSELY AFFECT OUR PERFORMANCE The power generation industry is characterized by intense competition. We encounter competition from utilities, industrial companies and other power producers. In recent years, there has been increasing competition in an effort to obtain power sales agreements. This competition has contributed to a reduction in electricity prices. In addition, many states have implemented or are considering regulatory initiatives designed to increase competition in the domestic power industry. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity. 15 20 OUR INTERNATIONAL INVESTMENTS MAY FACE UNCERTAINTIES We have one investment in geothermal steam fields located in Mexico and may pursue additional international investments. International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the countries in which we invest. Risks specifically related to investments in non-United States projects may include: - risks of fluctuations in currency valuation, - currency inconvertibility, - expropriation and confiscatory taxation, - increased regulation, and - approval requirements and governmental policies limiting returns to foreign investors. WE DEPEND ON OUR SENIOR MANAGEMENT Our success is largely dependent on the skills, experience and efforts of our senior management. The loss of the services of one or more members of our senior management could have a negative effect on our business, 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. OUR RESULTS ARE SUBJECT TO QUARTERLY AND SEASONAL FLUCTUATIONS Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including: - the timing and size of acquisitions, - the completion of development projects, and - variations in levels of production. Additionally, because we receive the majority of capacity payments under some of our power sales agreements during the months of May through October, our revenues and results of operations are, to some extent, seasonal. THE PRICE OF OUR COMMON STOCK IS VOLATILE The market price for our common stock has been volatile in the past, and several factors could cause the price to fluctuate substantially in the future. These factors include: - announcements of developments related to our business, - fluctuations in our results of operations, - sales of substantial amounts of our securities into the marketplace, 16 21 - general conditions in our industry or the worldwide economy, - an outbreak of war or hostilities, - a shortfall in revenues or earnings compared to securities analysts' expectations, - changes in analysts' recommendations or projections, and - announcements of new acquisitions or development projects by us. The market price of our common stock may fluctuate significantly in the future, and these fluctuations may be unrelated to our performance. General market price declines or market volatility in the future could adversely affect the price of our common stock, and the current market price may not be indicative of future market prices. WE COULD BE ADVERSELY AFFECTED IF OUR COMPUTER SYSTEMS ARE NOT YEAR 2000 COMPLIANT The "Year 2000 problem" refers to the fact that some computer hardware, software and embedded systems were designed to read and store dates using only the last two digits of the year. We are coordinating our efforts to address the impact of Year 2000 on our business through an analysis of four separate technology domains: - corporate applications, which include core business systems, - non-information technology, which includes all operating and control systems, - end-user computing systems (that is, systems that are not considered core business systems but may contain date calculations), and - business partner and vendor systems. We currently expect to complete our Year 2000 efforts with respect to critical systems by November of 1999. This schedule and our cost estimates may be affected by, among other things, the availability of Year 2000 personnel, the readiness of third parties, the timing for testing our embedded systems, the availability of vendor resources to complete embedded system assessments and produce required component upgrades and our ability to implement appropriate contingency plans. We produce revenues by selling power we produce to customers. We depend on transmission and distribution facilities that are owned and operated by investor-owned utilities to deliver power to our customers. If either our customers or the providers of transmission and distribution facilities experience significant disruptions as a result of the Year 2000 problem, our ability to sell and deliver power may be hindered, which could result in a loss of revenue. The cost or consequences of a materially incomplete or untimely resolution of the Year 2000 problem could adversely affect our future operations, financial results or our financial condition. WHERE YOU CAN FIND MORE INFORMATION We file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission. You may read and copy any document we file at the public reference facilities of the SEC located at 450 Fifth Street N.W., Washington D.C. 20549. You may obtain information on the operation of the SEC's public 17 22 reference facilities by calling the SEC at 1-800-SEC-0330. You can also access copies of such material electronically on the SEC's home page on the World Wide Web at http://www.sec.gov. This prospectus is part of a registration statement (Registration No. 333- ) we filed with the SEC. The SEC permits us to "incorporate by reference" the information we file with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus, and information that we file with the SEC after the date of this prospectus will automatically update and supersede this information. We incorporate by reference our Annual Report on Form 10-K as amended for the year ended December 31, 1998, our Quarterly Reports on Form 10-Q for the periods ended March 31, 1999 and June 30, 1999, and our Current Report on Form 8-K dated May 7, 1999, each filed by us with the SEC. We also incorporate by reference any future filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended, until we sell all of the shares of common stock and convertible preferred securities being registered or until this offering is otherwise terminated. If you request a copy of any or all of the documents incorporated by reference, then we will send to you the copies you requested at no charge. However, we will not send exhibits to such documents, unless such exhibits are specifically incorporated by reference in such documents. You should direct requests for such copies to Investor Relations, Calpine Corporation, 50 West San Fernando Street, San Jose, California 95113. Our telephone number is (408) 995-5115. FORWARD-LOOKING STATEMENTS Some of the statements in this prospectus and incorporated by reference are forward-looking statements. These statements involve known and unknown risks, uncertainties, and other factors that may cause our or our industry's actual results, levels of activity, performance, or achievements to be materially different from any future results, levels of activity, performance, or achievements expressed or implied by such forward-looking statements. Such factors include, among other things, those listed under "Risk Factors" and elsewhere in this prospectus. In some cases, you can identify forward-looking statements by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "potential," or "continue" or the negative of such terms or other comparable terminology. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance, or achievements. Moreover, neither we nor any other person assumes responsibility for the accuracy and completeness of such statements. We are under no duty to update any of the forward-looking statements after the date of this prospectus to conform such statements to actual results. 18 23 USE OF PROCEEDS The aggregate net proceeds to us from the sale of the 6,000,000 shares of common stock offered by us in the offering (after deducting underwriting discounts and commissions and estimated offering expenses) will be approximately $265.0 million ($304.7 million if the underwriters' over-allotment option in the common stock offering is exercised in full), assuming an offering price of $46.00 per share. We expect to use a substantial portion of the net proceeds from the offerings to finance power projects under development and construction. In addition, we expect to use $145.0 million of the net proceeds to complete the acquisition of 80% of CGCA and $53.0 million to complete the acquisition of Sheridan Energy. The remaining net proceeds, if any, will be used for working capital and general corporate purposes. See "Business -- Project Development and Acquisitions." Pending such uses, we expect to invest the net proceeds in short-term, interest-bearing securities. 19 24 PRICE RANGE OF COMMON STOCK Our common stock is traded on the New York Stock Exchange under the symbol "CPN." Public trading of the common stock commenced on September 20, 1996. Prior to that, there was no public market for the common stock. The following table sets forth, for the periods indicated, the high and low sale price per share of the common stock on the New York Stock Exchange. The information in the following table reflects the 2 for 1 stock split declared by us on September 20, 1999.
HIGH LOW ------- ------- 1997 First Quarter.............................................. $11.375 $ 8.563 Second Quarter............................................. 10.438 7.875 Third Quarter.............................................. 11.469 8.250 Fourth Quarter............................................. 10.625 6.188 1998 First Quarter.............................................. $ 9.250 $ 6.375 Second Quarter............................................. 10.625 8.625 Third Quarter.............................................. 10.750 8.563 Fourth Quarter............................................. 13.813 8.906 1999 First Quarter.............................................. $18.688 $12.625 Second Quarter............................................. 29.500 17.563 Third Quarter (through September 17, 1999)................. 47.875 27.406
As of September 17, 1999, there were approximately 71 holders of record of our common stock. On September 17, 1999, the last sale price reported on the New York Stock Exchange for our common stock was $46.375 per share. DIVIDEND POLICY We do not anticipate paying any cash dividends on our common stock in the foreseeable future because we intend to retain our earnings to finance the expansion of our business and for general corporate purposes. In addition, our ability to pay cash dividends is restricted under our indentures and our other debt agreements. Future cash dividends, if any, will be at the discretion of our board of directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual restrictions and such other factors as the board of directors may deem relevant. 20 25 CAPITALIZATION The following table sets forth, as of June 30, 1999 (1) the actual consolidated capitalization of the Company; and (2) the consolidated capitalization of our Company as adjusted for the sale of the shares of our common stock and convertible preferred securities in the offerings. This table should be read in conjunction with the consolidated financial statements and related notes thereto incorporated by reference in this prospectus.
JUNE 30, 1999 ------------------------- ACTUAL AS ADJUSTED ---------- ----------- UNAUDITED (DOLLARS IN THOUSANDS, EXCEPT SHARE AMOUNTS) CASH: Cash and cash equivalents........................... $ 320,287 $ 777,247 ========== ========== LONG-TERM DEBT: Non-recourse project financing, net of current portion.......................................... $ 79,210 $ 79,210 Senior notes........................................ 1,551,750 1,551,750 ---------- ---------- Total long-term debt........................ 1,630,960 1,630,960 ---------- ---------- Company-obligated convertible preferred securities of a subsidiary trust.................................. -- 192,000 STOCKHOLDERS' EQUITY: Preferred stock, $0.001 par value: 10,000,000 shares authorized; no shares outstanding, actual and as adjusted.............. -- -- Common stock, $0.001 par value: 100,000,000 shares authorized; 54,348,294 shares outstanding, actual; and 60,348,294 shares outstanding, as adjusted(1)(2)(3)................ 54 60 Additional paid-in capital.......................... 374,591 639,545 Retained earnings................................... 139,482 139,482 ---------- ---------- Total stockholders' equity.................. 514,127 779,087 ---------- ---------- Total capitalization..................... $2,145,087 $2,602,047 ========== ==========
- ------------------------- (1) Excludes the 900,000 shares that may be issued upon exercise of the underwriters' over-allotment option. (2) Does not include 3,202,649 shares of common stock subject to issuance upon exercise of options previously granted and outstanding as of June 30, 1999 under our 1996 Stock Incentive Plan. (3) Reflects 2 for 1 stock split declared by us on September 20, 1999. 21 26 SELECTED CONSOLIDATED FINANCIAL DATA The consolidated financial data set forth below for the five years ended and as of December 31, 1998 have been derived from the audited consolidated financial statements of our company. The consolidated financial data for the six months ended and as of June 30, 1998 and June 30, 1999 are unaudited, but have been prepared on the same basis as the audited consolidated financial statements and, in the opinion of management, contain all adjustments, consisting only of normal recurring adjustments, necessary for the fair presentation of the financial position and results of operations for these periods. Consolidated operating results for the six months ended June 30, 1999 should not be considered indicative of the results that may be expected for the entire year. The following selected consolidated financial data should be read in conjunction with the consolidated financial statements and the related notes thereto incorporated by reference in this prospectus.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, --------------------------------------------------- ------------------- 1994 1995 1996 1997 1998 1998 1999 ------- -------- -------- -------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) STATEMENT OF OPERATIONS DATA: Revenue: Electricity and steam sales........ $90,295 $127,799 $199,464 $237,277 $507,897 $178,798 $304,322 Service contract revenue from related parties.................. 7,221 7,153 6,455 10,177 20,249 8,529 13,238 Income (loss) from unconsolidated investments in power projects.... (2,754) (2,854) 6,537 15,819 25,240 6,853 18,321 Interest income on loans to power projects......................... -- -- 2,098 13,048 2,562 2,562 709 ------- -------- -------- -------- -------- -------- -------- Total revenue................ 94,762 132,098 214,554 276,321 555,948 196,742 336,590 Cost of revenue...................... 52,845 77,388 129,200 153,308 375,327 136,125 238,170 ------- -------- -------- -------- -------- -------- -------- Gross profit......................... 41,917 54,710 85,354 123,013 180,621 60,617 98,420 Project development expenses......... 1,784 3,087 3,867 7,537 7,165 3,119 4,248 General and administrative expenses........................... 7,323 8,937 14,696 18,289 26,780 11,043 20,964 Provision for write-off of project development costs.................. 1,038 -- -- -- -- -- -- ------- -------- -------- -------- -------- -------- -------- Income from operations............... 31,772 42,686 66,791 97,187 146,676 46,455 73,208 Interest expense..................... 23,886 32,154 45,294 61,466 86,726 40,790 47,171 Other (income) expense............... (1,988) (1,895) (6,259) (17,438) (13,423) (6,599) (11,068) ------- -------- -------- -------- -------- -------- -------- Income before provision for income taxes............................ 9,874 12,427 27,756 53,159 73,373 12,264 37,105 Provision for income taxes........... 3,853 5,049 9,064 18,460 27,054 3,393 14,545 ------- -------- -------- -------- -------- -------- -------- Income before extraordinary charge........................... 6,021 7,378 18,692 34,699 46,319 8,871 22,560 Extraordinary charge for retirement of debt, net of tax benefit of $--, $--, $--, $--, $441, $207 and $793............................... -- -- -- -- 641 302 1,150 ------- -------- -------- -------- -------- -------- -------- Net income......................... $ 6,021 $ 7,378 $ 18,692 $ 34,699 $ 45,678 $ 8,569 $ 21,410 ======= ======== ======== ======== ======== ======== ======== Basic earnings per common share: Weighted average shares of common stock outstanding................ 20,776 20,776 25,805 39,892 40,242 40,112 47,518 Income before extraordinary charge........................... $ 0.29 $ 0.36 $ 0.72 $ 0.87 $ 1.15 $ 0.22 $ 0.47 Extraordinary charge............... $ -- $ -- $ -- $ -- $ (0.02) $ (0.01) $ (0.02) Net income......................... $ 0.29 $ 0.36 $ 0.72 $ 0.87 $ 1.13 $ 0.21 $ 0.45 Diluted earnings per common share: Weighted average shares of common stock outstanding................ 21,842 21,913 29,758 42,032 42,328 42,100 50,469 Income before extraordinary charge........................... $ 0.28 $ 0.34 $ 0.63 $ 0.83 $ 1.10 $ 0.21 $ 0.45 Extraordinary charge............... $ -- $ -- $ -- $ -- $ (0.02) $ (0.01) $ (0.02) Net income......................... $ 0.28 $ 0.34 $ 0.63 $ 0.83 $ 1.08 $ 0.20 $ 0.43
22 27
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ---------------------------------------------------------- ----------------------- 1994 1995 1996 1997 1998 1998 1999 -------- -------- ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT RATIOS) (UNAUDITED) OTHER FINANCIAL DATA AND RATIOS: Depreciation and amortization.............. $ 21,580 $ 26,896 $ 40,551 $ 48,935 $ 82,913 $ 32,104 $ 45,449 EBITDA(1)................... $ 53,707 $ 69,515 $ 117,379 $ 172,616 $ 255,306 $ 93,374 $ 151,927 EBITDA to Consolidated Interest Expense(2)....... 2.23x 2.11x 2.41x 2.60x 2.74x 2.16x 2.92x Total debt to EBITDA........ 6.23x 5.87x 5.12x 4.96x 4.20x -- -- Ratio of earnings to fixed charges(3)................ 1.52x 1.46x 1.45x 1.64x 1.68x 1.11x 1.43x
AS OF DECEMBER 31, ---------------------------------------------------------- AS OF 1994 1995 1996 1997 1998 JUNE 30, 1999 -------- -------- ---------- ---------- ---------- ------------- (IN THOUSANDS) (UNAUDITED) BALANCE SHEET DATA: Cash and cash equivalents............ $ 22,527 $ 21,810 $ 95,970 $ 48,513 $ 96,532 $ 320,287 Property, plant and equipment, net... 335,453 447,751 648,208 736,339 1,094,303 1,568,882 Investments in power projects........ 11,114 8,218 13,936 222,542 221,509 234,584 Notes receivable..................... 16,882 25,785 36,143 117,357 10,899 16,202 Total assets......................... 421,372 554,531 1,031,397 1,380,915 1,728,946 2,549,750 Short-term debt...................... 27,300 85,885 37,492 112,966 5,450 -- Long-term line of credit............. -- 19,851 -- -- -- -- Non-recourse debt.................... 196,806 190,642 278,640 182,893 114,190 79,210 Notes payable........................ 5,296 6,348 -- -- -- -- Senior notes......................... 105,000 105,000 285,000 560,000 951,750 1,551,750 Total debt........................... 334,402 407,726 601,132 855,859 1,071,390 1,630,960 Stockholders' equity................. 18,649 25,227 203,127 239,956 286,966 514,127
- ------------------------- (1) EBITDA is defined as income from operations plus depreciation, capitalized interest, other income, non-cash charges and cash received from investments in power projects, reduced by the income from unconsolidated investments in power projects. EBITDA is presented here 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 either (a) to income from operations (determined in accordance with generally accepted accounting principles) or (b) to cash flows from operating activities (determined in accordance with generally accepted accounting principles). (2) For purposes of calculating the EBITDA to Consolidated Interest Expense ratio, Consolidated Interest Expense is defined as total interest expense plus one-third of all operating lease obligations, dividends paid in respect of preferred stock and cash contributions to any employee stock ownership plan used to pay interest on loans incurred to purchase our capital stock. (3) Earnings are defined as income before provision for taxes, extraordinary item and cumulative effect of change in accounting principle plus cash received from investments in power projects and fixed charges reduced by the equity in income from investments in power projects and capitalized interest. Fixed charges consist of interest expense, capitalized interest, amortization of debt issuance costs and the portion of rental expenses representative of the interest expense component. 23 28 PRO FORMA CONSOLIDATED FINANCIAL DATA The following unaudited pro forma consolidated statement of operations for the year ended December 31, 1998 gives effect to the following transactions as if such transactions had occurred on January 1, 1998: (1) our acquisition of the remaining 55% interest in the Bethpage Power Plant on February 5, 1998 (the "Bethpage Transaction"); (2) our acquisition of the remaining 50% interest in the Texas City Power Plant and the Clear Lake Power Plant on April 1, 1998 (the "Texas City/Clear Lake Transaction"); (3) our sale of $300 million of 7 7/8% Senior Notes Due 2008 on March 31, 1998, and the application of the net proceeds therefrom; and (4) our sale of $100 million of 7 7/8% Senior Notes Due 2008 on July 24, 1998 and the application of the net proceeds therefrom (the Bethpage Transaction, the Texas City/Clear Lake Transaction, the sale of $300 million of 7 7/8% Senior Notes Due 2008 and the sale of $100 million of 7 7/8% Senior Notes Due 2008 being collectively referred to as the "Transactions"). The pro forma consolidated financial data and Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements and related notes thereto incorporated by reference in this prospectus. The pro forma adjustments are based upon available information and certain assumptions that management believes are reasonable and are described in the notes accompanying the pro forma consolidated financial data. The pro forma consolidated financial data are presented for informational purposes only and do not purport to represent what our results of operations would actually have been had such transactions in fact occurred at such dates, or to project our results of operations for any future period. In the opinion of management, all adjustments necessary to present fairly such pro forma consolidated financial data have been made. 24 29 PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 ------------------------------------------------- ADJUSTMENTS PRO FORMA FOR THE FOR THE ACTUAL TRANSACTIONS TRANSACTIONS --------- ---------------- ------------------ (IN THOUSANDS, EXCEPT RATIOS AND PER SHARE DATA) STATEMENT OF OPERATIONS DATA: Revenue: Electricity and steam sales..................... $507,897 $ 74,163 $582,060 Service contract revenue from related parties... 20,249 (1,613) 18,636 Income from unconsolidated investments in power projects...................................... 25,240 (1,765) 23,475 Interest income on loans to power projects...... 2,562 (2,520) 42 -------- --------- -------- Total revenue............................ 555,948 68,265 624,213 -------- --------- -------- Cost of revenue: Plant operating expenses........................ 256,079 48,764 304,843 Depreciation.................................... 73,988 7,612 81,600 Production royalties............................ 10,714 -- 10,714 Operating lease expenses........................ 17,129 (1,277) 15,852 Service contract expenses....................... 17,417 -- 17,417 -------- --------- -------- Total cost of revenue.................... 375,327 55,099 430,426 -------- --------- -------- Gross profit...................................... 180,621 13,166 193,787 Project development expenses...................... 7,165 -- 7,165 General and administrative expenses............... 26,780 (27) 26,753 -------- --------- -------- Income from operations.......................... 146,676 13,193 159,869 Interest expense.................................. 86,726 8,302 95,028 Interest income................................... (12,348) -- (12,348) Other (income) expense............................ (1,075) (146) (1,221) -------- --------- -------- Income before provision for income taxes........ 73,373 5,037 78,410 Provision for income taxes........................ 27,054 1,689 28,743 -------- --------- -------- Income before extraordinary charge................ 46,319 3,348 49,667 Extraordinary charge for retirement of debt, net of tax benefit of $441, $-- and $441............ 641 -- 641 -------- --------- -------- Net income.................................... $ 45,678 $ 3,348 $ 49,026 ======== ========= ======== Basic earnings per common share: Weighted average shares of common stock outstanding................................... 40,242 40,242 Income before extraordinary charge.............. $ 1.15 $ 1.24 Extraordinary charge............................ $ (0.02) $ (0.02) Net income...................................... $ 1.13 $ 1.22 Diluted earnings per common share: Weighted average shares of common stock outstanding................................... 42,328 42,328 Income before extraordinary charge.............. $ 1.10 $ 1.18 Extraordinary charge............................ $ (0.02) $ (0.02) Net income...................................... $ 1.08 $ 1.16 OTHER OPERATING DATA AND RATIOS: Depreciation and amortization................... $ 82,913 $ 90,525 EBITDA.......................................... $255,306 $278,091 EBITDA to Consolidated Interest Expense......... 2.74x 2.74x Total debt to EBITDA............................ 4.20x 3.85x Ratio of earnings to fixed charges.............. 1.68x 1.69x
25 30 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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 September 10, 1999, we had interests in 37 power plants predominantly in the United States, having an aggregate capacity of 3,627 megawatts. On February 5, 1998, we acquired the remaining 55% interest in, and assumed operations and maintenance of, the Bethpage Power Plant. We purchased the remaining interests for approximately $5.0 million. Additionally, on March 31, 1998 we repaid all outstanding project debt of $37.4 million related to the Bethpage Power Plant. On March 31, 1998, we completed the acquisition of the remaining 50% interest in the Texas Cogeneration Company ("TCC"), which is the owner of the Texas City and Clear Lake Power Plants. We paid $52.8 million in cash and agreed to make certain contingent purchase payments that could approximate 2.2% of project revenue beginning in the year 2000, increasing to 2.9% in 2002. As part of this acquisition, we own a 7.5% interest in the Bayonne Power Plant, a 165 megawatt gas-fired cogeneration power plant located in Bayonne, New Jersey. In addition, we paid $105.3 million to restructure certain gas contracts related to this acquisition. On July 13, 1998, we signed a letter of intent to enter into a joint venture to develop, own and operate approximately 2,000 megawatts of gas-fired power plants in northern California primarily to serve the San Francisco Bay Area. The gas-fired plants are to be constructed by Bechtel and operated by us. We have announced that the first plant to be developed under the joint venture will be the Delta Energy Center, an 880 megawatt gas-fired plant located at the Dow Chemical facility in Pittsburg, California. On July 17, 1998, we completed the purchase of a 60 megawatt geothermal power plant located in Sonoma County, California, from the Sacramento Municipal Utility District ("SMUD") for $13.0 million. We are the owner and operator of the geothermal steam fields that provide steam to this facility. Under the agreement, we paid SMUD $10.6 million at closing, and agreed to pay an additional $2.4 million over the next two years. In connection with the acquisition, SMUD agreed to purchase up to 50 megawatts of electricity from the plant at current market prices plus a renewable power premium through 2001. In addition, SMUD has the option to purchase 10 megawatts of off-peak power production through 2005. We currently market the excess electricity into the California power market. On July 21, 1998, we completed the acquisition of a 70 megawatt gas-fired power plant from The Dow Chemical Company for approximately $13.1 million. The power plant is located at Dow's Pittsburg, California chemical facility. We will sell up to 18 megawatts of electricity to Dow under a ten-year power sales agreement, with the balance sold to Pacific Gas & Electric Company ("PG&E") under an existing power sales agreement. In addition, we will sell approximately 200,000 lbs./hr of steam to Dow and to USS-POSCO Industries' nearby steel mill. 26 31 In August 1998, we entered into a sale and leaseback transaction for certain plant and equipment of our Greenleaf 1 & 2 Power Plants, two 49.5 megawatt gas-fired cogeneration facilities located in Sutter County, California, for a net book value of $108.6 million. Under the terms of the agreement, we received approximately $559,000 for the sale of all our rights, title and interest in the stock of Calpine Greenleaf Corporation, and transferred all non-recourse project financing of $71.6 million and deferred taxes of $21.4 million. A loss of $15.6 million was recorded on the balance sheet and is being amortized over the term of the lease through June 2014. Additionally, we have an early purchase option expiring September 30, 2003. On September 28, 1998, we entered into a partnership agreement with Energy Management, Inc. ("EMI") to acquire an ownership interest in a 265 megawatt gas-fired plant under construction in Tiverton, Rhode Island. EMI and Calpine will be co-general partners for this project, with EMI acting as the managing general partner. We invested $40.0 million of equity in the power project, which is scheduled to commence commercial operation in May 2000. We will receive 62.8% of all cash and income distributions from the Tiverton project until we receive a 10.5% pre-tax rate of return. Thereafter, we will receive 50% of all distributions. On November 18, 1998, we entered into a partnership agreement with EMI to acquire an ownership interest in a 265 megawatt gas-fired plant under construction in Rumford, Maine. EMI and Calpine will be co-general partners for this project, with EMI acting as the managing general partner. We invested $40.0 million of equity in the power project, which is scheduled to commence commercial operation in July 2000. We will receive 66 2/3% of all cash and income distributions from the Rumford project until we receive a 10.5% pre-tax rate of return. Thereafter, we will receive 50% of all distributions. On January 4, 1999, we completed the acquisition of a 20% interest in 82 billion cubic feet of proven natural gas reserves located in the Sacramento basin of Northern California. We paid approximately $14.9 million for $13.0 million in redeemable non-voting preferred stock and 20% of the outstanding common stock of Sheridan California Energy, Inc. ("SCEI"). Additionally, we signed a ten year gas contract enabling us to purchase 100% of SCEI's production. On February 17, 1999, we announced that the Delta Energy Center met the California Energy Commission's Data Adequacy requirements. This ruling stated that our Application for Certification contained adequate information for the California Energy Commission to begin its analysis of the power plant's environmental impacts and proposed mitigation. The Delta Energy Center, an 880 megawatt gas-fired power plant located at the Dow Chemical facility in Pittsburg, California, is the first power plant that will be developed, owned and operated under a joint venture with Bechtel Enterprises, and will provide power to the Pittsburg, California and the greater San Francisco Bay Area. The gas-fired power plant is to be constructed by Bechtel and operated by us. On February 17, 1999, we announced plans to develop, own and operate a 545 megawatt gas-fired power plant in Westbrook, Maine. We acquired the development rights for the Westbrook Power Plant from Genesis Power Corporation. This power plant is scheduled to begin power deliveries in early 2001, and will serve the New England market. On February 24, 1999, we announced plans to develop, own and operate a 600 megawatt gas-fired power plant located in San Jose, California. This power plant, called the Metcalf Energy Center, is the second power plant to be developed under the 27 32 joint venture with Bechtel Enterprises, and will provide electricity to the San Francisco Bay area. We expect the plant to commence operation in mid 2002. On March 19, 1999, we completed the acquisition of Unocal Corporation's Geysers geothermal steam fields in northern California for approximately $102.1 million. The steam fields fuel our 12 Sonoma County power plants, totaling 544 megawatts of capacity. We purchased these plants from PG&E on May 7, 1999. On April 14, 1999, we received approval from the California Energy Commission to construct a 545 megawatt gas-fired power plant near Yuba City, California. This power plant, called the Sutter Power Plant, was the first new power plant approved in California's deregulated power industry. Electricity produced by the Sutter Power Plant will be sold into California's energy market. We expect the plant to commence operation in early 2001. On April 22, 1999, we entered into a joint venture with GenTex Power Corporation to develop, own and operate a 545 megawatt gas-fired power plant in Bastrop County, Texas, called Lost Pines I. Construction of this power plant is expected to begin in October 1999. Under the definitive agreements we entered in September 1999, we will manage all phases of the plant's development process, with GenTex and ourselves jointly operating the plant. The output from Lost Pines I will be divided equally, with GenTex selling its portion to its customer base, while we will sell our portion to the wholesale power market in Texas. We expect the plant to commence operation in mid-2001. On April 23, 1999, we entered into a joint agreement with Pinnacle West Capital Corporation to develop, own and operate a 545 megawatt gas-fired power plant located in Phoenix, Arizona. This plant, called the West Phoenix Power Plant, will provide power to the Phoenix metropolitan area, and construction will commence in 2000. We expect the plant to commence operation in 2002. On May 7, 1999, we completed the acquisitions from PG&E, of 12 Sonoma County and 2 Lake County power plants for approximately $212.8 million. The acquisitions were financed with a 24 year operating lease. Our geothermal steam fields fuel the facilities, which have a combined capacity of approximately 694 megawatts of electricity. All of the generation from the facilities is sold to the California energy market, with the exception of an agreement entered into on April 29, 1999, to sell to Commonwealth Energy Corporation 75 megawatts of geothermal electricity in 1999, 100 megawatts in 2000, and 125 megawatts in 2001 and through June 2002. Historically, we have served as a steam supplier for these facilities, which had been owned and operated by PG&E. These acquisitions have enabled us to consolidate our operations in The Geysers into a single ownership structure and to integrate the power plant and steam field operations, allowing us to optimize the efficiency and performance of the facilities. We believe that these acquisitions provide us with significant synergies that leverage our expertise in geothermal power generation and position us to benefit from the demand for "green" energy in the competitive market. On June 21, 1999, we acquired the rights to build, own and operate a 545 megawatt gas-fired power plant located in Ontelaunee Township, Pennsylvania. The plant, called the Ontelaunee Energy Center, will provide power to residences and businesses throughout the Pennsylvania-New Jersey-Maryland power pool. Construction will commence in 2000 and the plant is scheduled to begin production in 2002. On July 26, 1999, we announced plans to enter into a $1.0 billion revolving construction credit facility and expect to enter into definitive agreements in the fall of 1999. The non-recourse credit facility will serve as a key component of our development 28 33 program and will be utilized to finance the construction of our diversified portfolio of gas-fired power plants currently under development. We currently intend to refinance the construction facility in the longer-term capital markets prior to its four-year maturity. On August 20, 1999, we announced the purchase of 18 F-class combustion turbines from Siemens Westinghouse Power Corporation that will be capable of producing 4,900 megawatts of electricity in a combined-cycle configuration. Beginning in 2002, Siemens will deliver six turbines per year through 2004. Combined with our existing turbine order we have 69 turbines under contract, option or letter of intent capable of producing 17,745 megawatts. On August 31, 1999, we completed the acquisition of an additional 50% of the Aidlin Power Plant from Edison Mission Energy (5%) and General Electric Capital Corporation (45%) for a total purchase price of $7.2 million. We now own 55% of the 20-megawatt Aidlin Power Plant. On August 25, 1999, we announced an agreement with Sheridan Energy, Inc., a natural gas exploration and production company, to acquire Sheridan through a $41.0 million cash tender offer. We have offered to purchase all outstanding shares of Sheridan Energy's common stock for $5.50 per share. In addition, we have agreed to redeem $11.5 million of outstanding preferred stock of Sheridan Energy. We expect to complete the tender in October 1999. Sheridan Energy's oil and gas properties, including 148 billion cubic feet equivalent of proven reserves, are located in northern California and the Gulf Coast region, where we are developing low-cost natural gas supplies and proprietary pipeline systems to support our strategically-located natural gas-fired power plants. On August 27, 1999, we announced an agreement with CGCA to acquire 80% of its common stock for $25.00 per share or approximately $145.0 million. NRG Energy, Inc., a wholly owned subsidiary of Northern States Power, will own the remaining 20%. The transaction is subject to the approval of CGCA shareholders and we expect to consummate the acquisition by year-end 1999. CCGA currently owns interests in six natural gas-fired power plants, totaling 579 megawatts. The plants are located in Pennsylvania, New Jersey, Illinois and Oklahoma. SELECTED OPERATING INFORMATION Set forth below is certain selected operating information for the power plants and steam fields for which results are consolidated in our consolidated statements of operations. The information set forth under power plants consists of the results for the West Ford Flat Power Plant, Bear Canyon Power Plant, Greenleaf 1 & 2 Power Plants, Watsonville Power Plant, King City Power Plant, Gilroy Power Plant, the Bethpage Power Plant since its acquisition on February 5, 1998, the Texas City and Clear Lake Power Plants since their acquisition on March 31, 1998, the Pasadena Power Plant since it began commercial operation on July 7, 1998, the Sonoma Power Plant since its acquisition on July 17, 1998 and the Pittsburg Power Plant since its acquisition on July 21, 1998, and the 12 Sonoma County and 2 Lake County power plants purchased from PG&E on May 7, 1999. The 29 34 information set forth under steam fields consists of the results for the Thermal Power Company Steam Fields prior to the acquisition.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, -------------------------------------------------------------- ----------------------- 1994 1995 1996 1997 1998 1998 1999 ---------- ---------- ---------- ---------- ---------- ---------- ---------- (DOLLARS IN THOUSANDS) (UNAUDITED) POWER PLANTS: Electricity revenue (1): Energy................. $ 45,912 $ 54,886 $ 93,851 $ 110,879 $ 252,178 $ 93,735 $ 177,305 Capacity............... $ 7,967 $ 30,485 $ 65,064 $ 84,296 $ 193,535 $ 67,103 $ 106,155 Megawatt hours produced............. 447,177 1,033,566 1,985,404 2,158,008 9,864,080 2,217,659 5,516,805 Average energy price per kilowatt hour (2).................. 10.267c 5.310c 4.727c 5.138c 2.557c 4.227c 3.214c STEAM FIELDS: Steam revenue (3): Calpine................ $ 32,631 $ 39,669 $ 40,549 $ 42,102 $ 36,130 $ 17,960 $ 20,862 Other interest......... $ 2,051 $ -- $ -- $ -- $ -- $ -- $ -- Megawatt hours produced............. 2,156,492 2,415,059 2,528,874 2,641,422 2,323,623 981,114 1,192,722 Average price per kilowatt hour........ 1.608c 1.643c 1.603c 1.594c 1.555c 1.831c 1.749c
- ------------------------- (1) Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. (2) Represents variable energy revenue divided by the kilowatt-hours produced. The significant increase in capacity revenue and the accompanying decline in average energy price per kilowatt-hour since 1994 primarily reflects the increase in our megawatt hour production as a result of additional gas-fired power plants. (3) The decline in steam revenue between 1998 and 1997 reflects the acquisition and consolidation of the Sonoma Power Plant and the related steam fields. We completed several acquisitions of geothermal power plants and steam fields during 1999. Since the steam fields serve power plants owned by us following their acquisitions, our steam fields will no longer recognize steam revenue. 30 35 RESULTS OF OPERATIONS SIX MONTHS ENDED JUNE 30, 1999 COMPARED TO SIX MONTHS ENDED JUNE 30, 1998 Revenue -- Total revenue increased 71% to $336.6 million for the six months ended June 30, 1999 compared to $196.7 million for the same period in 1998. Electricity and steam sales revenue for the six months ended June 30, 1999 increased 70% to $304.3 million as compared to $178.8 million for the same period a year ago. This increase is primarily due to an increase of $106.3 million for power plants that were acquired during the first half of 1998, and $32.7 million for our Pasadena plant that became operational in the third quarter of 1998, partially offset by a decrease of $21.6 million at the Bear Canyon and West Ford Flat Power Plants relating to the expiration of the fixed priced period of their power sales agreements. Service contract revenue increased to $13.2 million for the six months ended June 30, 1999 compared to $8.5 million for the same period in 1998. The increase was primarily attributable to third party excess gas sales, as well as an increase for fuel management fees. Income from unconsolidated investments in power projects for the six months ended June 30, 1999 increased 167% to $18.3 million as compared to $6.9 million for the same period a year ago. This increase is primarily attributable to an increase of $11.4 million of equity income from our investment in Sumas, an increase of $1.5 million of equity income from our investment in the Bayonne Power Plant, and an increase of $1.1 million from our Kennedy International Airport Power Plant. These increases were partially offset by a reduction of $2.9 million in equity income from our Texas City and Clear Lake Power Plants, which were consolidated on March 31, 1998. Interest income on loans to power projects for the six months ended June 30, 1999 decreased to $709,000 compared to $2.6 million for the same period a year ago. The decrease is primarily related to the acquisition of the remaining 50% interest in Texas Cogeneration Company on March 31, 1998, offset by dividend income received from Sheridan California Energy. Cost of revenue -- Cost of revenue increased to $238.2 million for the six months ended June 30, 1999 compared to $136.1 million for the same period in 1998. The increase of $102.1 million was primarily attributable to increased plant operating, fuel and depreciation expenses as a result of the acquisition of the remaining interests in the Texas City, Clear Lake Power Plants on March 31, 1998, the acquisition of the remaining interest in the Bethpage Power Plant on February 5, 1998, the acquisition of the Pittsburg Power Plant on July 21, 1998, the consolidation of our Geysers operations on May 7, 1999 and the startup of the Pasadena Power Plant in July of 1998. General and administrative expenses -- General and administrative expenses for the six months ended June 30, 1999 increased to $21.0 million compared to $11.0 million for the same period in 1998. The increase was attributable to continued growth in personnel and associated overhead costs necessary to support the overall growth in our operations. Interest expense -- Interest expense for the six months ended June 30, 1999 increased to $47.2 million from $40.8 million for the same period a year ago. The increase was primarily attributable to $21.8 million of interest associated with the issuances of senior 31 36 notes in 1999 and 1998, partially offset by an increase in capitalized interest of $10.3 million, and a decrease in interest expense of $4.7 million related to the retirement of non-recourse project financing for the Greenleaf Power Plant in 1998 and the Gilroy Power Plant in 1999. Provision for income taxes -- The effective income tax rate was approximately 39% for the six months ended June 30, 1999. The reductions from the statutory tax rate was primarily due to depletion in excess of tax basis benefits at our geothermal facilities, and a decrease in the California taxes paid due to our expansion into states other than California. YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 Revenue -- Total revenue increased 101% to $555.9 million in 1998 compared to $276.3 million in 1997. Electricity and steam sales revenue increased 114% to $507.9 million in 1998 compared to $237.3 million in 1997. The increase is primarily attributable to the acquisition of the remaining interest in the Texas City, Clear Lake and Bethpage Power Plants and the acquisition of the Pittsburg Power Plant. These power plants accounted for $245.2 million in additional electricity revenues in 1998. We benefited from the startup of our power plant in Pasadena, Texas, which became operational in July 1998. This power plant contributed $30.5 million in revenue during 1998. During 1998, we produced 9,864,080 total electricity megawatt hours, which was 7,706,072 megawatt hours higher than the same period in 1997, as a result of the factors described above. We recently announced three acquisitions, which we expect to complete during 1999, upon government approval. These acquisitions when completed will eliminate steam revenue for The Geysers, reflecting the consolidation of the acquired power plants and related steam fields. Service contract revenue increased 98% to $20.2 million in 1998 compared to $10.2 million in 1997. The $10.0 million increase was primarily due to $3.3 million for fuel management fees, and $7.5 million for third party excess gas sales. Income from unconsolidated investments in power projects increased 59% to $25.2 million in 1998 compared to $15.8 million in 1997. The increase of $9.4 million is primarily attributable to our investments in the Lockport, Stony Brook and Kennedy International Airport Power Plants, which contributed $5.2 million of equity income during 1998, as well as $2.5 million of equity income from the Bayonne Power Plant. For the year ended December 31, 1998, we also recorded $11.7 million of equity income from the Sumas Power Plant compared to $8.5 million for the same period in 1997. These increases in equity income were partially offset by a $1.1 million decrease from the Auburndale Power Plant. Interest income on loans to power projects decreased 80% to $2.6 million in 1998 compared to $13.0 million in 1997. This decrease was attributable to the acquisition of the remaining 50% interest in TCC on March 31, 1998 and the sale of a note receivable in December 1997. Cost of revenue -- Cost of revenue increased to $375.3 million in 1998 compared to $153.3 million in 1997. The increase of $222.0 million in 1998 was primarily attributable to increased plant operating, fuel and depreciation expenses as a result of the acquisition of the remaining interest in the Texas City, Clear Lake and Bethpage Power Plants, the acquisition of the Pittsburg Power Plant and the startup of the Pasadena Power Plant. 32 37 Additionally, service contract expenses increased $8.8 million for the year ended December 31, 1998, of which $6.6 million was related to costs associated with the sale of third party excess gas and a $1.8 million increase for fuel management contracts. General and administrative expenses -- General and administrative expenses increased 46% to $26.8 million in 1998 compared to $18.3 million in 1997. The increase was attributable to the continued growth in personnel and overhead costs necessary to support the overall growth in our operations. Interest expense -- Interest expense increased 41% to $86.7 million in 1998 compared to $61.5 million in 1997. The increase was primarily attributable to interest expense of $35.0 million related to the senior notes issued in 1998 and 1997. This increase was partially offset by $3.5 million for the repayment of non-recourse project financing for our Geysers facilities, $2.9 million for reduction of the TCC debt, $2.0 million for reduction of the indebtedness of the Greenleaf 1 & 2 Power Plants and $1.7 million of interest capitalized on the development and construction of power projects. Interest income -- Interest income decreased 14% to $12.3 million in 1998 compared to $14.3 million in 1997. The decrease was primarily attributable to less interest earned on restricted cash in 1998. Other income, net -- Other income decreased 66% to $1.1 million in 1998 compared to $3.2 million in 1997. The decrease was primarily attributable to gas refunds received in 1997. Provision for income taxes -- The effective income tax rate was approximately 37% in 1998 compared to 35% in 1997. The effective rates were lower than the statutory rate (federal and state) primarily due to depletion in excess of tax basis benefits at our geothermal facilities, and a decrease in the California tax liability due to our expansion into states other than California. YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996 Revenue -- Total revenue increased 29% to $276.3 million in 1997 compared to $214.6 million in 1996. Electricity and steam sales revenue increased 19% to $237.3 million in 1997 compared to $199.5 million in 1996. Electricity and steam sales revenue for 1997 reflected a full year of operation at the Gilroy and King City Power Plants, which contributed to increases in electricity and steam sales revenue in 1997 compared to 1996 of $25.4 million, and $4.3 million, respectively. Electricity and steam sales revenue for 1997 compared to 1996 was also $6.0 million higher at the Bear Canyon and West Ford Flat Power Plants as a result of increased production and an increase in fixed energy prices to 13.83c per kilowatt-hour. During 1996, the Bear Canyon and West Ford Flat Power Plants experienced the maximum curtailment allowed under their power sales agreements with PG&E. In May 1997, the power sales agreements for the Bear Canyon and West Ford Flat Power Plants were modified to remove curtailment. Without such curtailment, these plants generated an additional $4.2 million in revenues in 1997 as compared to 1996. In addition, Thermal Power Company ("TPC") also contributed $2.7 million more revenue for 1997 than 1996, primarily due to increased steam sales under the alternative pricing agreement entered into with PG&E in March 1996. 33 38 Service contract revenue increased to $10.2 million in 1997 compared to $6.5 million in 1996. Service contract revenue during 1996 reflected a $2.8 million loss from our electricity trading operations. The increase in service contract revenue for 1997 was also attributable to $2.8 million of revenue from the Texas City and Clear Lake Power Plants, which were acquired in June 1997. Income from unconsolidated investments in power projects increased to $15.8 million in 1997 compared to $6.5 million during 1996. The increase in 1997 compared to 1996 was primarily due to equity income of $6.3 million from our June 1997 investment in the Texas City and Clear Lake Power Plants and an increase in equity income of $2.2 million from our investment in Sumas Cogeneration Company ("Sumas"). In accordance with a power sales agreement with Puget Sound Power and Light Company, operations at Sumas were significantly displaced from February to July 1997, and, in exchange, the Sumas Power Plant received a higher price for energy sold and certain other payments. In addition, the partnership agreement governing Sumas was amended in September 1997 to increase our percentage of distributions. Interest income on loans to power projects increased to $13.0 million in 1997 compared to $2.1 million in 1996. The increase was primarily related to interest income on the loans made by Calpine Finance Company, a wholly-owned subsidiary of our company, to the Texas City and Clear Lake Power Plants, and to interest income on the loans to the sole shareholder of Sumas Energy, Inc., our partner in Sumas. Cost of revenue -- Cost of revenue increased 19% to $153.3 million in 1997 compared to $129.2 million in 1996. Plant operating, depreciation, and operating lease expenses at the Gilroy and King City Power Plants for 1997 reflected a full year of operations, which contributed to increases in cost of revenue in 1997 compared to 1996 of $13.0 million and $8.3 million, respectively. Project development expenses -- Project development expenses increased 92% to $7.5 million in 1997 compared to $3.9 million in 1996, due primarily to expanded acquisition and development activities. General and administrative expenses -- General and administrative expenses increased 24% to $18.3 million in 1997 compared to $14.7 million in 1996. The increases were primarily due to additional personnel and related expenses necessary to support our expanding operations. Interest expense -- Interest expense increased 36% to $61.5 million in 1997 from $45.3 million in 1996. The increase was attributable to: (1) $10.8 million of interest expense related to the 8 3/4% Senior Notes Due 2007 issued in July and September 1997, (2) a $7.3 million increase in interest expense related to the 10 1/2% Senior Notes Due 2006 issued May 1996, (3) a $6.4 million increase in interest expense on debt related to the Gilroy Power Plant acquired in August 1996 and (4) $5.4 million of interest expense on debt related to the acquisition of the Texas City and Clear Lake Power Plants. These increases were offset by $6.2 million of interest capitalized for the development and construction of power plants, and a $7.6 million decrease in interest expense at Calpine Geysers Company and TPC due to repayment of debt. Interest income -- Interest income increased 66% to $14.3 million for 1997 compared with $8.6 million for 1996. Interest income earned on collateral securities purchased in April 1996 in connection with the King City Power Plant contributed to an increase in interest income of $1.2 million in 1997 as compared to 1996. In addition, higher cash and cash 34 39 equivalent balances resulting from the issuance of the 8 3/4% Senior Notes Due 2007 during 1997 resulted in higher interest income for 1997 as compared to 1996. Other income, net -- Other income, net, increased to $3.2 million for 1997 compared with expense of $2.3 million for 1996. In 1997, we recorded a $1.1 million gain on the sale of a note receivable and received a refund of $961,000 from PG&E. In 1996, we recorded a $3.7 million loss for uncollectible amounts related to an acquisition project. Provision for income taxes -- The effective rate for the income tax provision was approximately 35% in 1997 and 33% in 1996. The effective rates were lower than the statutory tax rate (federal and state) primarily due to depletion in excess of tax basis benefits at our geothermal facilities, a decrease in the California taxes paid due to our expansion into states other than California, and a revision of prior years' tax estimates. LIQUIDITY AND CAPITAL RESOURCES To date, we have obtained cash from our operations, borrowings under our credit facilities and other working capital lines, sale of debt and equity, and proceeds from non-recourse project financing. We utilized this cash to fund our operations, service debt obligations, fund the acquisition, development and construction of power generation facilities, finance capital expenditures and meet our other cash and liquidity needs. The following table summarizes our cash flow activities for the periods indicated:
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, --------------------------------- --------------------- 1996 1997 1998 1998 1999 --------- --------- --------- --------- --------- (IN THOUSANDS) (UNAUDITED) Cash flows from: Operating activities......... $ 59,944 $ 108,461 $ 171,233 $ 23,073 $ 58,555 Investing activities......... (330,937) (402,158) (406,657) (174,923) (590,328) Financing activities......... 345,153 246,240 283,443 203,696 755,528 --------- --------- --------- --------- --------- Total................. $ 74,160 $ (47,457) $ 48,019 $ 51,846 $ 223,755 ========= ========= ========= ========= =========
Operating activities for the six months ended June 30, 1999 provided $58.6 million, consisting of approximately $44.1 million of depreciation and amortization, $21.4 million of net income, $25.5 million of distributions from unconsolidated investments in power projects, $13.3 million of deferred income taxes, and a $7.2 million net increase in operating liabilities. This was offset by $34.6 million net increase in operating assets and $18.3 million of income from unconsolidated investments. Operating activities for 1998 provided $171.2 million, consisting of approximately $74.3 million of depreciation and amortization, $45.7 million of net income, $34.4 million of distributions from unconsolidated investments in power projects, $13.6 million of deferred income taxes, $5.2 million net decrease in operating assets, and a $23.4 million net increase in operating liabilities. This was offset by $25.2 million of income from unconsolidated investments. Investing activities for the six months ended June 30, 1999 used $590.3 million, primarily due to $102.2 million for the acquisition of steam fields from Unocal, $14.9 million for the acquisition of a 20% interest in SCEI, a $15.8 million increase in restricted cash, $79.3 million of capital expenditures related to the construction of the Pasadena Power Plant Expansion, $344.6 million of other capital expenditures principally for turbine purchases and for the Clear Lake Expansion project, $33.8 million of capitalized project development costs, $14.0 million of interest capitalized on construction 35 40 projects, $8.4 million of additional loans to principal owners of power plants, $655,000 for the acquisition of additional investments, offset by $1.9 million of maturities of collateral securities in connection with the King City Power Plant, the repayment of $3.1 million of outstanding loans, and $18.4 million from the sale and leaseback transaction of the Geysers Power Company plants. Investing activities for 1998 used $406.7 million, primarily due to $158.1 million for the acquisition of the remaining 50% interest in the Texas City and Clear Lake Power Plants, $42.4 million for the acquisition of the remaining 55% interest in the Bethpage Power Plant, $24.0 million of capital expenditures related to the construction of the Pasadena Power Plant, $13.1 million for the acquisition of the Pittsburg Power Plant, $11.9 million for the acquisition of the Sonoma Power Plant, $74.2 million of other capital expenditures, $16.2 million of capitalized project development costs, $40.0 million for the acquisition of an equity interest in the Tiverton Power Plant, $40.0 million for the acquisition of an equity interest in the Rumford Power Plant, $7.0 million of interest capitalized on construction projects, offset by $559,000 related to the sale and leaseback transaction of the Greenleaf 1 & 2 Power Plants, the receipt of $13.8 million of loan payments, $6.0 million of maturities of collateral securities in connection with the King City Power Plant, and $1.1 million of restricted cash. Financing activities for the six months ended June 30, 1999 provided $755.5 million of cash consisting of $79.2 million of borrowings for the construction of the Pasadena Power Plant, $77.6 million of borrowings related to a bridge facility, $794.8 million of net proceeds from additional equity and senior debt financings received in March and April of 1999, and $1.2 million for the issuance of common stock for our Employee Stock Purchase Plan, partially offset by $120.6 million in repayment of non-recourse project financing in April 1999, and $77.6 million of repayments related to a bridge facility. Financing activities for 1998 provided $283.4 million of cash consisting of $52.1 million of borrowings for the construction of the Pasadena Power Plant, $5.8 million of borrowings for contingent consideration in connection with the acquisition of the Gilroy Power Plant, $394.9 million of net proceeds from additional financings, and $1.1 million for the issuance of common stock, partially offset by $162.1 million in repayment of non-recourse project financing, $8.3 million of repurchase of Senior Notes Due 2006 which includes a premium paid and accrued interest to the date of repurchase. At June 30, 1999, cash and cash equivalents were $320.3 million and working capital was $346.4 million. For 1999, cash and cash equivalents increased by $223.8 million and working capital increased by $259.5 million as compared to December 31, 1998. At December 31, 1998, cash and cash equivalents were $96.5 million and working capital was $86.9 million. For 1998, cash and cash equivalents increased by $48.0 million and working capital increased by $112.6 million as compared to December 31, 1997. As a developer, owner and operator of power generation facilities, we are required to make long-term commitments and investments of substantial capital for our projects. We historically have financed these capital requirements with cash from operations, borrowings under our credit facilities, other lines of credit, non-recourse project financing or long-term debt, and the sale of equity. We continue to evaluate current and forecasted cash flow as a basis for financing operating requirements and capital expenditures. We believe that we will have sufficient liquidity from cash flow from operations, borrowings available under the lines of credit and working capital to satisfy all obligations under outstanding indebtedness, to finance anticipated capital expenditures and to fund working capital requirements for the next twelve months. 36 41 On January 4, 1999, we entered into a Credit Agreement with ING to provide up to $265.0 million of non-recourse project financing for the construction of the Pasadena facility expansion. As of June 30, 1999, $79.2 million was outstanding as a construction loan under the agreement. The outstanding loan bears interest at ING's base rate plus an applicable margin or at LIBOR plus an applicable margin and is payable quarterly. The construction loan will convert to a term loan once the project has completed construction. The construction loan will mature on or before July 1, 2000, but is subject to an extension to October 1, 2000 if there are sufficient construction funds available. The term loan will be available for a period not to exceed five years from the construction loan maturity date. In connection with the Credit Agreement, we entered into a $10.0 million letter of credit facility. At June 30, 1999, there were no letters of credit outstanding under the facility. On March 26, 1999, we completed a public offering of 12,000,000 shares of our common stock at $15.50 per share. The net proceeds from this public offering were approximately $177.9 million. Additionally, in April 1999, we sold an additional 1,800,000 shares of common stock at $15.50 per share pursuant to the exercise of the underwriters' over-allotment option for net proceeds of approximately $26.7 million. On March 29, 1999, we completed a public offering of $250.0 million of our 7 5/8% Senior Notes Due 2006 and of our $350.0 million 7 3/4% Senior Notes Due 2009. After deducting underwriting discounts and expenses of the offering, the aggregate net proceeds from the sale of the Senior Notes were approximately $588.3 million. The Senior Notes Due 2006 bear interest at 7 5/8% per year, payable semi-annually on April 15 and October 15 each year and mature on April 15, 2006. The Senior Notes Due 2006 are not redeemable prior to maturity. The Senior Notes Due 2009 bear interest at 7 3/4% per year, payable semi-annually on April 15 and October 15 each year and mature on April 15, 2009. The Senior Notes Due 2009 are not redeemable prior to maturity. The net proceeds from the sale of the common stock, the Senior Notes Due 2006, and the Senior Notes Due 2009 were used as follows: (1) $120.6 million to refinance indebtedness relating to the Gilroy Power Plant, (2) $77.6 million to repay indebtedness under a bridge facility provided by Credit Suisse First Boston to finance a portion of the purchase price to acquire the steam fields that service the Sonoma County power plants, (3) $50.0 million to repay outstanding borrowings under our revolving credit facility, $23.4 million of which was incurred to finance a portion of the steam fields that service the Sonoma Power Plants, (4) $25.0 million to complete the expansion of the Clear Lake Power Plant, (5) approximately $400.0 million to finance a portion of power generation facilities currently under construction and the projects currently under development, and (6) the remaining $119.6 million will be used for general corporate purposes. Transaction costs incurred in connection with the senior notes offered were recorded as deferred charge and are amortized over the respective lives of the Senior Notes Due 2006 and the Senior Notes Due 2009 using the effective interest rate method. At June 30, 1999, we had a $100.0 million revolving credit facility available with a consortium of commercial lending institutions. We had no borrowings and $20.9 million of letters of credit outstanding under the credit facility. The credit facility contains certain restrictions that limit or prohibit, among other things, the ability of Calpine or its subsidiaries to incur indebtedness, make payments of certain indebtedness, pay dividends, make investments, engage in transactions with affiliates, create liens, sell assets and engage in mergers and consolidations. 37 42 At June 30, 1999, 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. At June 30, 1999, we had a $12.0 million letter of credit outstanding with The Bank of Nova Scotia to secure performance of the Clear Lake Power Plant. We have a $1.1 million working capital line with a commercial lender that may be used to fund short-term working capital commitments and letters of credit. At June 30, 1999, we had no borrowings under this working capital line and $74,000 of letters of credit outstanding. Borrowings accrue interest at prime plus 1%. FINANCIAL MARKET RISKS From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations. We do not use derivative financial instruments for speculative or trading purposes. The following table summarizes the fair market value of our existing interest rate swap agreements as of June 30, 1999 (in thousands):
WEIGHTED NOTIONAL AVERAGE MATURITY DATE PRINCIPAL AMOUNT INTEREST RATE FAIR MARKET VALUE - ------------- ---------------- ------------- ----------------- 2000 $ 21,800 9.9% $ (571) 2009 65,000 6.1% 1,156 2013 75,000 7.2% (3,480) 2014 79,970 6.7% (1,423) ---------------- ------------- ----------------- Total $241,770 7.1% $(4,318) ================ ============= =================
Short-term investments. As of June 30, 1999, we have short-term investments of $271.3 million. These short-term investments consist of highly liquid investments with maturities between three and twelve months. These investments are subject to interest rate risk and will increase in value if market interest rates increase. We have the ability to hold these investments to maturity, and as a result, we would not expect the value of these investments to be affected to any significant degree by the effect of a sudden change in market interest rates. Declines in interest rates over time will reduce our interest income. 38 43 Outstanding debt. As of June 30, 1999, we have outstanding long-term debt of approximately $1.6 billion primarily made up of $1.5 billion of senior notes and $79.2 million of construction financing. Our construction financing has a floating interest rate which has averaged 6.8%. Our outstanding long-term senior notes as of June 30, 1999 are as follows (in thousands):
MATURITY DATE CARRYING AMOUNT INTEREST RATE FAIR MARKET VALUE - ------------- --------------- ------------- ----------------- 2004 $ 105,000 9 1/4% $ 106,050 2006 171,750 10 1/2% 185,267 2006 250,000 7 5/8% 243,125 2007 275,000 8 3/4% 282,219 2008 400,000 7 7/8% 384,600 2009 350,000 7 3/4% 330,313 --------------- ----------------- Total $1,551,750 $1,513,574 =============== =================
Gas prices fluctuations. We enter into derivative commodity instruments to hedge our exposure to the impact of price fluctuations on gas purchases. Such instruments include regulated natural gas contracts and over-the-counter swaps and basis hedges with major energy derivative product specialists. All hedge transactions are subject to our risk management policy which does not permit speculative positions. These transactions are accounted for under the hedge method of accounting. Cash flows from derivative instruments are recognized as incurred through changes in working capital. IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS In June 1999, the FASB issued FASB Statement No. 137 entitled "Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of FASB Statement No. 133." The Statement would amend SFAS No. 133 to defer its effective date to all fiscal quarters of all fiscal years beginning after June 15, 2000. We have not yet analyzed the impact of adopting SFAS No. 133 on the financial statements and have not determined the timing of or method of the adoption of SFAS No. 133. However, the Statement could increase the volatility of our earnings. YEAR 2000 COMPLIANCE Year 2000 Compliance -- The "Year 2000 problem" refers to the fact that some computer hardware, software and embedded systems were designed to read and store dates using only the last two digits of the year. We are coordinating our efforts to address the impact of Year 2000 on our business through a Year 2000 Project Team comprised of representatives from each business unit and our Year 2000 Project Office. The Year 2000 Project Office is charged with addressing additional Year 2000 related issues including, but not limited to, business continuation and other contingency planning. The Year 2000 Project Team meets regularly to monitor the efforts of assigned staff and contractors to identify, remediate and test our technology. The Year 2000 Project Team is focusing on four separate technology domains: - corporate applications, which include core business systems, - non-information technology, which includes all operating and control systems, 39 44 - end-user computing systems (that is, systems that are not considered core business systems but may contain date calculations), and - business partner and vendor systems. Corporate Applications -- Corporate applications are those major core systems, such as customer information, human resources and general ledger, for which our Management Information Systems department has responsibility. We utilize PeopleSoft for our major core systems. The PeopleSoft applications we utilize are in operation and have been determined to be Year 2000 compliant. Non-Information Technology/Embedded Systems -- Non-information technology includes such items as power plant operating and control systems, telecommunications and facilities-based equipment (e.g. telephones and two-way radios) and other embedded systems. Each business unit is responsible for the inventory and remediation of its embedded systems. In addition, we are working with the Electric Power Research Institute, a consortium of power companies, including investor-owned utilities, to coordinate vendor contacts and product evaluation. Because many embedded systems are similar across utilities, this concentrated effort should help to reduce total time expended in this area and help to ensure that our efforts are consistent with the efforts and practices of other power companies and utilities. An Inventory phase for non-information technology/embedded systems was completed in October 1998. An Initial Assessment phase was completed in December 1998. We plan to complete remediation of non-compliant systems by the third quarter of 1999. To date, all embedded systems that we have identified can be upgraded or modified within our current schedule. The schedule for addressing Year 2000 issues with respect to mission critical embedded systems is as follows:
PERCENTAGE PHASE COMPLETED STATUS ESTIMATED COMPLETION DATE - ---------------------- ---------- ----------- -------------------------- Inventory............. 100% Complete September 1998 Initial Assessment.... 100% Complete November 1998 Detail Assessment..... 100% Complete May 1999 Remediation........... 98% In Progress September 1999 Contingency 5% Planning............ In Progress November 1999
Testing of embedded systems is complex because some of the testing must be completed during power plant scheduled maintenance outages. Much of the testing will be accomplished in the fall of 1999 during regularly scheduled maintenance outage periods. At that time, at least one typical unit of each critical type will be tested by us or in cooperation with other power companies, and the requirement for further testing will be determined. End-User Computing Systems -- Some of our business units have developed systems, databases, spreadsheets, etc. that contain date calculations. Compliance of individual workstations is also included in this domain. These systems comprise a relatively small percentage of the required modification in terms of both number and criticality. Our end-user computing systems are being inventoried by each business unit and evaluated and remediated by our MIS staff. We expect to complete this process by year-end 1999. 40 45 Business Partner and Vendor Systems -- We have contracts with business partners and vendors who provide products and services to us. We are vigorously seeking to obtain Year 2000 assurances from these third parties. The Year 2000 Project Team and appropriate business units are jointly undertaking this effort. We have sent letters and accompanying Year 2000 surveys to about 800 vendors and suppliers. Over 600 responses have been received as of July 31, 1999. These responses outline to varying degrees the approaches vendors are undertaking to resolve Year 2000 issues within their own systems. Follow-up letters will be sent to those vendors who have not responded or whose responses were inadequate. Contingency Planning -- Contingency and business continuation planning are in various stages of development for critical and high-priority systems. Our existing disaster response plan and other contingency plans are currently being evaluated and will be adopted for use in case of any Year 2000-related disruption. We expect to complete our contingency planning by November 1999. Costs -- The costs of expected modifications are currently estimated to be approximately $1.7 million which will be charged to expense as incurred. From January 1, 1999 through June 30, 1999, $321,000 was charged to expense. Approximately 9% of the estimated total cost was incurred in 1998, 63% will be incurred in 1999 and the remainder will be incurred in 2000. These costs have been and will be funded through operating cash flow. These estimates may change as additional evaluations are completed and remediation and testing progress. Risks -- We currently expect to complete our Year 2000 efforts with respect to critical systems by the fall of 1999. This schedule and our cost estimates may be affected by, among other things, the availability of Year 2000 personnel, the readiness of third parties, the timing for testing our embedded systems, the availability of vendor resources to complete embedded system assessments and produce required component upgrades and our ability to implement appropriate contingency plans. We produce revenues by selling power we produce to customers. We depend on transmission and distribution facilities that are owned and operated by investor-owned utilities to deliver power to our customers. If either our customers or the providers of transmission and distribution facilities experience significant disruptions as a result of the Year 2000 problem, our ability to sell and deliver power may be hindered, which could result in a loss of revenue. The cost or consequences of a materially incomplete or untimely resolution of the Year 2000 problem could adversely affect our future operations, financial results or our financial condition. 41 46 BUSINESS 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 37 power plants having an aggregate capacity of 3,627 megawatts and have an acquisition pending in which we will acquire 80% of CGCA which owns interests in 6 power plants with an aggregate capacity of 579 megawatts. We also have 6 gas-fired projects and one project expansion under construction having an aggregate capacity of 3,440 megawatts and have announced plans to develop 6 gas-fired power plants with a total capacity of 3,665 megawatts. Upon completion of pending acquisitions and projects under construction, we will have interests in 49 power plants located in 14 states having an aggregate capacity of 7,646 megawatts, of which we will have a net interest in 6,541 megawatts. This represents significant growth from the 342 megawatts of capacity we had at the end of 1993. Of this total generating capacity, 89% will be attributable to gas-fired facilities and 11% will be attributable to geothermal facilities. As a result of our expansion program, our revenues, cash flow, earnings and assets have grown significantly over the last five years, as shown in the table below.
COMPOUND ANNUAL 1993 1998 GROWTH RATE -------- ---------- --------------- (DOLLARS IN MILLIONS) Total Revenue..................... $ 69.9 $ 555.9 51% EBITDA............................ 42.4 255.3 43% Net Income........................ 3.8 45.7 64% Total Assets...................... 302.3 1,728.9 42%
Since our inception in 1984, we have developed substantial expertise in all aspects of the development, acquisition and operation of power generation facilities. We believe that the vertical integration of our extensive engineering, construction management, operations, fuel management and financing capabilities provides us with a competitive advantage to successfully implement our acquisition and development program and has contributed to our significant growth over the past five years. THE MARKET The power industry represents the third largest industry in the United States, with an estimated end-user market of over $250 billion of electricity sales in 1998 produced by an aggregate base of power generation facilities with a capacity of approximately 750,000 megawatts. In response to increasing customer demand for access to low-cost electricity and enhanced services, new regulatory initiatives have been and are continuing to be adopted at both the state and federal level to increase competition in the domestic power generation industry. The power generation industry historically has been largely characterized by electric utility monopolies producing electricity from old, inefficient, high-cost generating facilities selling to a captive customer base. Industry trends and regulatory initiatives have transformed the existing market into a more competitive market where end users purchase electricity from a variety of suppliers, including non-utility generators, power marketers, public utilities and others. 42 47 There is a significant need for additional power generating capacity throughout the United States, both to satisfy increasing demand, as well as to replace old and inefficient generating facilities. Due to environmental and economic considerations, we believe this new capacity will be provided predominantly by gas-fired facilities. We believe that these market trends will create substantial opportunities for efficient, low-cost power producers that can produce and sell energy to customers at competitive rates. In addition, as a result of a variety of factors, including deregulation of the power generation market, utilities, independent power producers and industrial companies are disposing of power generation facilities. To date, numerous utilities have sold or announced their intentions to sell their power generation facilities and have focused their resources on the transmission and distribution segments. Many independent producers operating a limited number of power plants are also seeking to dispose of their plants in response to competitive pressures, and industrial companies are selling their power plants to redeploy capital in their core businesses. STRATEGY Our strategy is to continue our rapid growth by capitalizing on the significant opportunities in the power market, primarily through our active development and acquisition programs. In pursuing our proven growth strategy, we utilize our extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach uses our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations and power marketing, which we believe provides us with a competitive advantage. The key elements of our strategy are as follows: - Development and expansion of power plants. We are actively pursuing the development and expansion of highly efficient, low-cost, gas-fired power plants to replace old and inefficient generating facilities and meet the demand for new generation. Our strategy is to develop power plants in strategic geographic locations that enable us to utilize existing power generation assets and operate the power plants as integrated electric generation systems. This allows us to achieve significant operating synergies and efficiencies in fuel procurement, power marketing and operations and maintenance. In May 1999, we completed a 35 megawatt expansion of our Clear Lake Power Plant to 412 megawatts, and we commenced commercial operations at our 169 megawatt Dighton Power Plant in August 1999. We currently have seven projects under construction representing an additional 3,440 megawatts. Of these new projects, we are currently expanding our Pasadena facility by 545 megawatts to 785 megawatts and we have six new power plants under construction, including the Tiverton Power Plant in Rhode Island; the Rumford Power Plant in Maine; the Westbrook Power Plant in Maine; the Sutter Power Plant in California; the South Point Power Plant in Arizona; and the Magic Valley Power Plant in Texas. We have also announced plans to develop six additional power generation facilities, totaling 3,665 megawatts, in California, Texas, Arizona and Pennsylvania. In July 1999, we announced an agreement with Credit Suisse First Boston, New York branch and The Bank of Nova Scotia, as lead arrangers, for a $1.0 billion revolving construction loan facility. The credit facility will be utilized to finance the 43 48 construction of our development program. We expect to finalize the documentation relating to this facility in the third quarter of 1999. On August 20, 1999, we announced the purchase of 18 F-class combustion turbines from Siemens Westinghouse Power Corporation that will be capable of producing 4,900 megawatts of electricity. Beginning in 2002, Siemens will deliver six turbines per year through 2004. Combined with our existing turbine order we have 69 turbines under contract, option or letter of intent capable of producing 17,745 megawatts. - 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. We have significantly expanded and diversified our project portfolio through the acquisition of power generation facilities through the completion of 32 acquisitions to date. On March 19, 1999, we completed the acquisition of Unocal Corporation's Geysers geothermal steam fields in northern California for approximately $102.1 million. The steam fields fuel our 12 Sonoma County power plants, totaling 544 megawatts purchased from Pacific Gas and Electric Company. On May 7, 1999 we completed the acquisition from Pacific Gas and Electric Company ("PG&E") of 14 geothermal power plants at The Geysers in northern California, with a combined capacity of approximately 700 megawatts, for $212.8 million. With the acquisition, we now own interests in and operate 18 geothermal power plants that generate more than 800 megawatts of electricity, and we are the nation's largest geothermal and green power producer. The combination of our existing geothermal steam and power plant assets, the acquisition of the Sonoma steam fields from Unocal, and the 14 power plants from PG&E allows us to fully integrate the steam and power plant operations at The Geysers into one efficient, unified system to maximize the renewable natural resource, lower overall production costs and extend the life of The Geysers. On August 31, 1999, we completed the acquisition of an additional 50% of the Aidlin Power Plant from Edison Mission Energy (5%) and General Electric Capital Corporation (45%) for a total purchase price of $7.2 million. We now own 55% of the 20 megawatt Aidlin Power Plant. On August 25, 1999, we announced an agreement with Sheridan Energy, Inc., a natural gas exploration and production company, to acquire Sheridan through a $41.0 million cash tender offer. We have offered to purchase all outstanding shares of Sheridan Energy's common stock for $5.50 per share. In addition, we have agreed to redeem $11.5 million of outstanding preferred stock of Sheridan Energy. We expect to complete the tender in October 1999. Sheridan Energy's oil and gas properties, including 148 billion cubic feet equivalent of proven reserves, are located in northern California and the Gulf Coast region, where we are developing low-cost natural gas supplies and proprietary pipeline systems to support our strategically-located natural gas-fired power plants. On August 27, 1999, we announced an agreement with CGCA to acquire 80% of its common stock for $25.00 per share or approximately $145.0 million. NRG Energy, Inc., a wholly owned subsidiary of Northern States Power, will own the remaining 44 49 20%. The transaction is subject to the approval of CGCA shareholders and we expect to consummate the acquisition by year-end 1999. CCGA currently owns interests in six natural gas-fired power plants, totaling 579 megawatts. The plants are located in Pennsylvania, New Jersey, Illinois and Oklahoma. - 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. This will become even more significant as our portfolio of power generation facilities expands to an aggregate of 49 power plants with an aggregate capacity of 7,646 megawatts, after completion of our pending acquisitions and projects currently under construction. We focus on operating our plants as an integrated system of power generation, which enables us to minimize costs and maximize operating efficiencies. As of June 30, 1999, our gas-fired and geothermal power generation facilities have operated at an average availability of approximately 96% and 99%, respectively. We believe that achieving and maintaining a low-cost of production will be increasingly important to compete effectively in the power generation market. On July 8, 1999, we announced a renegotiation of our Gilroy power sales agreement with PG&E. The amendment provides for the termination of the remaining 18 years of the long-term contract in exchange for a fixed long-term payment schedule. The amended agreement is subject to approval by the California Public Utilities Commission, whose decision we expect to receive in the fourth quarter of 1999. We will continue to sell the output from the Gilroy Power Plant through October 2002 to PG&E and thereafter we will market the output in the California wholesale power market. DESCRIPTION OF FACILITIES We currently have interests in 37 power generation facilities with a current aggregate capacity of approximately 3,627 megawatts, consisting of 19 gas-fired power plants with a total capacity of 2,806 megawatts and 18 geothermal power generation facilities with a total capacity of 821 megawatts. We also have an acquisition pending comprising 6 gas-fired facilities with an aggregate capacity of 579 megawatts, 6 gas-fired projects and one project expansion currently under construction with an aggregate capacity of 3,440 megawatts, and have announced the development of 6 additional power plants with an aggregate capacity of 3,665 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. 45 50 Upon completion of the pending acquisitions and projects under construction, we will provide operating and maintenance services for 39 of the 49 power plants in which we have an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps, gathering systems and gas pipelines. We also supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operating and maintenance manuals for each power generation facility that we operate. As a facility develops an operating history, we analyze its operation and may modify or upgrade equipment or adjust operating procedures or maintenance measures to enhance the facility's reliability or profitability. These services are performed under the terms of an operating and maintenance agreement pursuant to which we are generally reimbursed for certain costs, paid an annual operating fee and may also be paid an incentive fee based on the performance of the facility. The fees payable to us are generally subordinated to any lease payments or debt service obligations of non-recourse financing for the project. In order to provide fuel for the gas-fired power generation facilities in which we have an interest, natural gas reserves are acquired or natural gas is purchased from third parties under supply agreements. We attempt to structure a gas-fired power facility's fuel supply agreement so that gas costs have a direct relationship to the fuel component of revenue energy payments. We currently hold interests in geothermal leaseholds in The Geysers that produce steam that is supplied to the power generation facilities owned by us for use in producing electricity. Certain power generation facilities in which we have an interest have been financed primarily with non-recourse project financing that is structured to be serviced out of the cash flows derived from the sale of electricity, thermal energy and/or steam produced by such facilities and provides that the obligations to pay interest and principal on the loans are secured almost solely by the capital stock or partnership interests, physical assets, contracts and/or cash flow attributable to the entities that own the facilities. The lenders under non-recourse project financing generally have no recourse for repayment against us or any of our assets or the assets of any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities that own the facilities. Substantially all of the power generation facilities in which we have an interest are located on sites which are leased on a long-term basis. See "-- Properties." 46 51 Set forth below is a map showing the locations of our power plants in operation, pending acquisitions, power plants under construction and announced development projects. [DEPICTION OF A MAP OF THE UNITED STATES, WITH MARKERS INDICATING THE LOCATION OF OUR FACILITIES]
MEGAWATTS ----------------------- # OF PLANT CALPINE NET PLANTS CAPACITY INTEREST ------ -------- ----------- In operation.................................... 37 3,627 2,888 Pending acquisitions............................ 6 579 400 Under construction -- New facilities............................. 6 2,895 2,708 -- Expansion projects......................... -- 545 545 Announced development........................... 6 3,665 2,380 -- ------ ----- 55 11,311 8,921 == ====== =====
47 52 Set forth below is certain information regarding our operating power plants, plants under construction, pending power plant acquisitions and development projects.
POWER NAMEPLATE CALPINE CALPINE NET GENERATION CAPACITY INTEREST INTEREST POWER PLANT TECHNOLOGY LOCATION (MEGAWATTS)(1) PERCENTAGE (MEGAWATTS) ----------- ---------- ------------- -------------- ---------- ----------- OPERATING POWER PLANTS Sonoma County (12 power plants)(3)............ Geothermal California 544.0 100% 544.0 Texas City.............. Gas-Fired Texas 450.0 100% 450.0 Clear Lake.............. Gas-Fired Texas 412.0 100% 412.0 Pasadena................ Gas-Fired Texas 240.0 100% 240.0 Gordonsville............ Gas-Fired Virginia 240.0 50% 120.0 Lockport................ Gas-Fired New York 184.0 11.4% 20.9 Dighton(6).............. Gas-Fired Massachusetts 169.0 50% 84.5 Bayonne................. Gas-Fired New Jersey 165.0 7.5% 12.4 Auburndale.............. Gas-Fired Florida 150.0 50% 75.0 Lake County (2 power plants)(3)............ Geothermal California 150.0 100% 150.0 Sumas(2)................ Gas-Fired Washington 125.0 70% 87.5 King City............... Gas-Fired California 120.0 100% 120.0 Gilroy.................. Gas-Fired California 120.0 100% 120.0 Kennedy International Airport............... Gas-Fired New York 107.0 50% 53.5 Pittsburg............... Gas-Fired California 70.0 100% 70.0 Sonoma(3)............... Geothermal California 60.0 100% 60.0 Bethpage................ Gas-Fired New York 57.0 100% 57.0 Greenleaf 1............. Gas-Fired California 49.5 100% 49.5 Greenleaf 2............. Gas-Fired California 49.5 100% 49.5 Stony Brook............. Gas-Fired New York 40.0 50% 20.0 Agnews.................. Gas-Fired California 29.0 20% 5.8 Watsonville............. Gas-Fired California 28.5 100% 28.5 West Ford Flat.......... Geothermal California 27.0 100% 27.0 Bear Canyon............. Geothermal California 20.0 100% 20.0 Aidlin.................. Geothermal California 20.0 55% 11.0 PENDING ACQUISITIONS Grays Ferry............. Gas-Fired Pennsylvania 150.0 40% 60.0 Parlin.................. Gas-Fired New Jersey 122.0 80% 97.6 Morris.................. Gas-Fired Illinois 117.0 80% 93.6 Pryor................... Gas-Fired Oklahoma 110.0 80% 88.0 Newark.................. Gas-Fired New Jersey 58.0 80% 46.4 Philadelphia............ Gas-Fired Pennsylvania 22.0 66.4% 14.6 PROJECTS UNDER CONSTRUCTION Magic Valley............ Gas-Fired Texas 730.0 100% 730.0 Westbrook............... Gas-Fired Maine 545.0 100% 545.0 Pasadena Expansion...... Gas-Fired Texas 545.0 100% 545.0 South Point............. Gas-Fired Arizona 545.0 100% 545.0 Sutter.................. Gas-Fired California 545.0 100% 545.0 Tiverton(4)............. Gas-Fired Rhode Island 265.0 62.8% 166.4 Rumford(5).............. Gas-Fired Maine 265.0 66.7% 176.8
48 53
POWER NAMEPLATE CALPINE CALPINE NET GENERATION CAPACITY INTEREST INTEREST POWER PLANT TECHNOLOGY LOCATION (MEGAWATTS)(1) PERCENTAGE (MEGAWATTS) ----------- ---------- ------------- -------------- ---------- ----------- ANNOUNCED DEVELOPMENT Delta Energy Center..... Gas-Fired California 880.0 50% 440.0 Metcalf Energy Center... Gas-Fired California 600.0 50% 300.0 Pittsburg............... Gas-Fired California 550.0 100% 550.0 Lost Pines 1............ Gas-Fired Texas 545.0 50% 272.5 West Phoenix............ Gas-Fired Arizona 545.0 50% 272.5 Ontelaunee.............. Gas-Fired Pennsylvania 545.0 100% 545.0
- ------------------------- (1) Nameplate capacity may not represent the actual output for a facility at any particular time. (2) See "-- Operating Power Plants -- Sumas Power Plant" for a description of our interest in the Sumas Power Plant. Based on our current estimates, the payments to be received by us represent approximately 70% of distributable cash. (3) For these geothermal power plants, nameplate capacity refers to the approximate capacity of the power plants. The capacity of these plants is expected to gradually diminish as the production of the related steam fields declines. (4) See "Project Development and Acquisitions -- Project Development -- Projects Under Construction -- Tiverton Power Plant" for a description of our interest in the Tiverton Power Plant. (5) See "Project Development and Acquisitions -- Project Development -- Projects Under Construction -- Rumford Power Plant" for a description of our interest in the Rumford Power Plant. (6) See "Project Development and Acquisitions -- Project Development -- Projects Under Construction -- Dighton Power Plant" for a description of our interest in the Dighton Power Plant. Based on our current estimates, our interest represents our right to receive approximately 50% of project cash flow beginning at the commencement of commercial operation. OPERATING POWER PLANTS Sonoma County Power Plants. The Sonoma County power plants consist of 12 geothermal power plants and associated steam fields having combined capacity of 544 megawatts located at The Geysers in northern California. The power plants were acquired from PG&E on May 7, 1999 and we market the output from these plants into the California power market. Texas City Power Plant. The Texas City Power Plant is a 450 megawatt gas-fired cogeneration facility located in Texas City, Texas. Electricity generated by the Texas City Power Plant is sold under two separate long-term agreements to (1) Texas Utilities Electric Company ("TUEC") under a power sales agreement terminating on September 30, 2002, and (2) Union Carbide Corporation ("UCC") under a steam and electricity services agreement terminating on June 30, 1999. Each agreement contains payment provisions for capacity and electric energy payments. Under a steam and electricity services agreement expiring October 19, 2003, the Texas City Power Plant will supply UCC with 300,000 lbs/hr of steam on a monthly average basis, with the required supply of steam not exceeding 600,000 lbs/hr at any given time. During 1998, the Texas 49 54 City Power Plant generated approximately 2,517,316,000 kilowatt hours of electric energy for sale to TUEC and UCC and approximately $188.3 million of revenue. Clear Lake Power Plant. The Clear Lake Power Plant is a 412 megawatt gas/ hydrogen-fired cogeneration facility located in Pasadena, Texas. Electricity generated by the Clear Lake Power Plant is sold under three separate long-term agreements to (1) Texas-New Mexico Power Company ("TNP") under a power sales agreement terminating in 2004, (2) Houston Lighting and Power Company ("HL&P") under a power sales agreement terminating in 2005, and (3) Hoechst Celanese Chemical Group, Inc. ("HCCG") under a power sales agreement terminating in 2004. Each power sales agreement contains payment provisions for capacity and energy payments. Under a steam purchase and sale agreement expiring August 31, 2004, the Clear Lake Power Plant will supply up to 900,000 lbs/hr of steam to HCCG. During 1998, the Clear Lake Power Plant generated approximately 2,912,649,000 kilowatt hours of electric energy for sale to TNP, HL&P and HCCG and approximately $89.3 million of revenue. Pasadena Power Plant. The Pasadena Power Plant is a 240 megawatt gas-fired cogeneration facility located in Pasadena, Texas. Electricity generated by the Pasadena Power Plant is sold under contract and into the open market. We entered into an energy sales agreement with Phillips Petroleum Company ("Phillips") terminating in 2018. Under this agreement, we provide 90 megawatts of electricity and 200,000 lbs/hr of steam to Phillips' Houston Chemical Complex. West Texas Utilities purchased 50 megawatts of capacity through the end of 1998. In 1999, LG&E Energy Marketing will purchase up to 150 megawatts of electricity under a one-year agreement. TUEC is also under contract to purchase up to 150 megawatts of electricity under a two-year agreement beginning December 1, 1999. The remaining available electricity output is sold into the competitive market through our power marketing organization. During 1998, the Pasadena Power Plant generated approximately 812,314,000 kilowatt hours of electric energy with approximately $30.5 million of revenue. Gordonsville Power Plant. The Gordonsville Power Plant is a 240 megawatt gas-fired cogeneration facility located near Gordonsville, Virginia. Electricity generated by the Gordonsville Power Plant is sold to the Virginia Electric and Power Company under two power sales agreements terminating on June 1, 2024, each of which include payment provisions for capacity and energy. The Gordonsville Power Plant sells steam to Rapidan Service Authority under the terms of a steam purchase and sales agreement, which expires June 1, 2004. During 1998, the Gordonsville Power Plant generated approximately 213,382,000 kilowatt hours of electrical energy and approximately $37.4 million of revenue. Lockport Power Plant. The Lockport Power Plant is a 184 megawatt gas-fired, combined-cycle cogeneration facility located in Lockport, New York. The facility is owned and operated by Lockport Energy Associates, L.P. ("LEA"). We own an indirect 11.36% limited partnership interest in LEA. Electricity and steam is sold to General Motors Corporation ("GM") under an energy sales agreement expiring in December 2007 for use at the GM Harrison plant, which is located on a site adjacent to the Lockport Power Plant. Electricity is also sold to New York State Electricity and Gas Company ("NYSEG") under a power purchase agreement expiring October 2007. NYSEG is required to purchase all of the electric power produced by the Lockport Power Plant not required by GM. For 1998, the Lockport Power Plant generated approximately 1,284,830,000 kilowatt hours of electricity and had $118.6 million in revenue. 50 55 Dighton Power Plant. In October 1997, we invested $16.0 million in the development of a 169 megawatt gas-fired combined-cycle power plant to be located in Dighton, Massachusetts. This investment, which is structured as subordinated debt, will provide us with a preferred payment stream at a rate of 12.07% per year for a period of twenty years from the commercial operation date. The Dighton Power Plant was developed by EMI and cost approximately $120.0 million. Commercial operation commenced in August 1999. The Dighton Power Plant is operated by EMI and sells its output into the New England power market and to wholesale and retail customers in the northeastern United States. Bayonne Power Plant. The Bayonne Power Plant is a 165 megawatt gas-fired cogeneration facility located in Bayonne, New Jersey. The facility is primarily owned by an affiliate of Cogen Technologies, Inc. We own an indirect 7.5% limited partnership interest in the facility. Electricity generated by the Bayonne Power Plant is sold under various power sales agreements to Jersey Central Power & Light Company and Public Service Electric and Gas Company of New Jersey. The Bayonne Power Plant also sells steam to two industrial entities. During 1998, the Bayonne Power Plant generated approximately 1,399,860,000 kilowatt hours of electrical energy and approximately $116.6 million in revenue. Auburndale Power Plant. The Auburndale Power Plant is a 150 megawatt gas-fired cogeneration facility located near the city of Auburndale, Florida. Electricity generated by the Auburndale Power Plant is sold under various power sales agreements to Florida Power Corporation ("FPC"), Enron Power Marketing and Sonat Power Marketing. Auburndale sells 131.18 megawatts of capacity and energy to FPC under three power sales agreements, each terminating at the end of 2013. The Auburndale Power Plant sells steam under two steam purchase and sale agreements. One agreement is with Cutrale Citrus Juices, USA, an affiliate of Sucocitro Cutrale LTDA, expiring on July 1, 2014. The second agreement is with Todhunter International, Inc., doing business as Florida Distillers Company, expiring on July 1, 2009. During 1998, the Auburndale Power Plant generated approximately 1,022,146,000 kilowatt hours of electrical energy and approximately $49.6 million in revenue. Lake County Power Plants. The Lake County power plants consist of two geothermal power plants and associated steam fields having a combined capacity of 150 megawatts located at The Geysers in northern California. We acquired these power plants from PG&E on May 7, 1999, and we market the output from these plants into the California power market. Sumas Power Plant. The Sumas Power Plant is a 125 megawatt gas-fired, combined cycle cogeneration facility located in Sumas, Washington. We currently hold an ownership interest in the Sumas Power Plant, which entitles us to receive certain scheduled distributions during the next two years. Upon receipt of the scheduled distributions, we will no longer have any ownership interest in the Sumas Power Plant. Electrical energy generated by the Sumas Power Plant is sold to Puget Sound Power & Light Company ("Puget") under the terms of a power sales agreement terminating in 2013. Under the power sales agreement, Puget has agreed to purchase an annual average of 123 megawatts of electrical energy. In addition to the sale of electricity to Puget, pursuant to a long-term steam supply and dry kiln lease agreement, the Sumas Power Plant produces and sells approximately 23,000 lbs/hr of low pressure steam to an adjacent lumber-drying facility owned by Sumas, which has been leased to and is operated by Socco, Inc. During 1998, the Sumas Power Plant generated approximately 915,227,280 kilowatt hours of electrical energy and approximately $49.6 million of total revenue. 51 56 King City Power Plant. The King City Power Plant is a 120 megawatt gas-fired, combined-cycle cogeneration facility located in King City, California. We operate the King City Power Plant under a long-term operating lease for this facility with BAF Energy ("BAF"), terminating in 2018. Electricity generated by the King City Power Plant is sold to PG&E under a power sales agreement terminating in 2019. The power sales agreement contains payment provisions for capacity and energy. In addition to the sale of electricity to PG&E, the King City Power Plant produces and sells thermal energy to a thermal host, Basic Vegetable Products, Inc., an affiliate of BAF, under a long-term contract coterminous with the power sales agreement. During 1998, the King City Power Plant generated approximately 428,825,000 kilowatt hours of electrical energy and approximately $45.6 million of total revenue. Gilroy Power Plant. The Gilroy Power Plant is a 120 megawatt gas-fired cogeneration facility located in Gilroy, California. Electricity generated by the Gilroy Power Plant is sold to PG&E under a power sales agreement terminating in 2018. In July 1999 we announced a renegotiation of our Gilroy power sales agreement with PG&E. The amendment provides for the termination of the remaining 18 years of the long-term contract in exchange for a fixed long-term payment schedule. The amended agreement is subject to approval by the California Public Utilities Commission, whose decision we expect to receive in the fourth quarter of 1999. We will continue to sell the output from the Gilroy Power Plant through October 2002 to PG&E and thereafter we will market the output in the California wholesale power market. In addition, the Gilroy Power Plant produces and sells thermal energy to a thermal host, Gilroy Foods, Inc., under a long-term contract that is coterminous with the power sales agreement. During 1998, the Gilroy Power Plant generated approximately 477,628,000 kilowatt hours of electrical energy for sale to PG&E and approximately $39.3 million in revenue. Kennedy International Airport Power Plant. The Kennedy International Airport Power Plant is a 107 megawatt gas-fired cogeneration facility located at John F. Kennedy International Airport in Queens, New York. The facility is owned and operated by KIAC Partners. We own an indirect 50% general partnership interest in KIAC. Electricity and thermal energy generated by the Kennedy International Airport Power Plant is sold to the Port Authority, and incremental electric power is sold to Consolidated Edison Company of New York, the New York Power Authority and other utility customers. Electric power and chilled and hot water generated by the Kennedy International Airport Power Plant is sold to the Port Authority under an energy purchase agreement that expires November 2015. For 1998, the Kennedy International Airport Power Plant generated approximately 533,755,000 kilowatt hours of electrical energy, 266,252 mmbtu of chilled water and 178,405 mmbtu of hot water for sale to the Port Authority, and generated approximately $56.1 million in revenue. Pittsburg Power Plant. The Pittsburg Power Plant is a 70 megawatt gas-fired cogeneration facility, located at The Dow Chemical Company's ("Dow") Pittsburg, California chemical facility. We sell up to 18 megawatts of electricity to Dow under a power sales agreement expiring in 2008. Surplus energy is sold to PG&E under an existing power sales agreement. In addition, we sell approximately 200,000 lbs/hr of steam to Dow under an energy sales agreement expiring in 2003 and to USS-POSCO Industries' nearby steel mill under a process steam contract expiring in 2001. From its acquisition, in July 1998, through the end of 1998, the Pittsburg Power Plant generated approximately 92,358,000 kilowatt hours of electrical energy to Dow and PG&E and approximately $9.4 million in revenue. 52 57 Sonoma Power Plant. The Sonoma Power Plant consists of a 60 megawatt geothermal power plant and associated steam fields located in Sonoma County, California. Electricity generated by the Sonoma Power Plant is sold to the Sacramento Municipal Utility District ("SMUD") under a power sales agreement for up to 50 megawatts of off-peak power production, terminating in 2001. In addition, SMUD has the option to purchase up to an additional 10 megawatts of peak power production through 2005. We market the excess electricity into the California power market. From its acquisition, in June 1998, through the end of 1998, the Sonoma Power Plant generated approximately 215,433,000 kilowatt hours of electrical energy and approximately $6.2 million in revenue. Bethpage Power Plant. The Bethpage Power Plant is a 57 megawatt gas-fired, combined cycle cogeneration facility located adjacent to a Northrup Grumman Corporation ("Grumman") facility in Bethpage, New York. Electricity and steam generated by the Bethpage Power Plant are sold to Grumman under an energy purchase agreement expiring August 2004. Electric power not sold to Grumman is sold to Long Island Power Authority ("LIPA") under a generation agreement also expiring August 2004. Grumman is also obligated to purchase a minimum of 158,000 klbs of steam per year from the Bethpage Power Plant. For 1998, the Bethpage Power Plant generated approximately 474,991,000 kilowatt hours of electrical energy for sale to Grumman and LIPA and approximately $32.9 million in revenue. Greenleaf 1 Power Plant. The Greenleaf 1 Power Plant is a 49.5 megawatt gas-fired cogeneration facility located near Yuba City, California. We operate this facility under an operating lease with Union Bank of California, terminating in 2014 (the "Greenleaf Lease"). Electricity generated by the Greenleaf 1 Power Plant is sold to PG&E under a power sales agreement terminating in 2019 which contains payment provisions for capacity and energy. In addition, the Greenleaf 1 Power Plant sells thermal energy, in the form of hot exhaust to dry wood waste, to a thermal host which is owned and operated by us. For 1998, the Greenleaf 1 Power Plant generated approximately 326,543,000 kilowatt hours of electrical energy for sale to PG&E and approximately $17.8 million in revenue. Greenleaf 2 Power Plant. The Greenleaf 2 Power Plant is a 49.5 megawatt gas-fired cogeneration facility located near Yuba City, California. This facility is also operated by us under the Greenleaf Lease. Electricity generated by the Greenleaf 2 Power Plant is sold to PG&E under a power sales agreement terminating in 2019 which includes payment provisions for capacity and energy. In addition to the sale of electricity to PG&E, the Greenleaf 2 Power Plant sells thermal energy to Sunsweet Growers, Inc. pursuant to a 30-year contract. For 1998, the Greenleaf 2 Power Plant generated approximately 377,101,000 kilowatt hours of electrical energy for sale to PG&E and approximately $20.3 million in revenue. Stony Brook Power Plant. The Stony Brook Power Plant is a 40 megawatt gas-fired cogeneration facility located on the campus of the State University of New York at Stony Brook, New York ("SUNY"). The facility is owned by Nissequogue Cogen Partners ("NCP"). We own an indirect 50% general partner interest in NCP. Steam and electric power is sold to SUNY under an energy supply agreement expiring in 2023. Under the energy supply agreement, SUNY is required to purchase, and the Stony Brook Power Plant is required to provide, all of SUNY's electric power and steam requirements up to 36.125 megawatts of electricity and 280,000 lbs/hr of process steam. The remaining electricity is sold to LIPA under a long-term agreement. LIPA is obligated to purchase electric power generated by the facility not required by SUNY. SUNY is required to purchase a minimum of 402,000 klbs per year of steam. For 1998, the Stony Brook Power Plant generated 53 58 approximately 326,584,000 kilowatt hours of electrical energy and 1,185,000 klbs of steam for sale to SUNY and LIPA and approximately $31.1 million in revenue. Agnews Power Plant. The Agnews Power Plant is a 29 megawatt gas-fired, combined-cycle cogeneration facility located on the East Campus of the state-owned Agnews Developmental Center in San Jose, California. We hold a 20% ownership interest in GATX Calpine-Agnews, Inc., which is the sole stockholder of O.L.S. Energy-Agnews, Inc. ("O.L.S. Energy-Agnews"). O.L.S. Energy-Agnews leases the Agnews Power Plant under a sale leaseback arrangement. Electricity generated by the Agnews Power Plant is sold to PG&E under a power sales agreement terminating in 2021 which contains payment provisions for capacity and energy. In addition, the Agnews Power Plant produces and sells electricity and approximately 7,000 lbs/hr of steam to the Agnews Developmental Center pursuant to a 30-year energy service agreement. During 1998, the Agnews Power Plant generated approximately 215,180,000 kilowatt hours of electrical energy and total revenue of $11.7 million. Watsonville Power Plant. The Watsonville Power Plant is a 28.5 megawatt gas-fired, combined cycle cogeneration facility located in Watsonville, California. We operate the Watsonville Power Plant under an operating lease with the Ford Motor Credit Company, terminating in 2009. Electricity generated by the Watsonville Power Plant is sold to PG&E under a power sales agreement terminating in 2009 which contains payment provisions for capacity and energy. During 1998, the Watsonville Power Plant produced and sold steam to Farmers Processing, a food processor. In addition, the Watsonville Power Plant sold process water produced from its water distillation facility to Farmer's Cold Storage, Farmer's Processing and Cascade Properties. For 1998, the Watsonville Power Plant generated approximately 206,007,000 kilowatt hours of electrical energy for sale to PG&E and approximately $11.4 million in revenue. West Ford Flat Power Plant. The West Ford Flat Power Plant consists of a 27 megawatt geothermal power plant and associated steam fields located in northern California. Electricity generated by the West Ford Flat Power Plant is sold to PG&E under a power sales agreement terminating in 2008 which contains payment provisions for capacity and energy. During 1998, the West Ford Flat Power Plant generated approximately 235,529,000 kilowatt hours of electrical energy for sale to PG&E and approximately $34.6 million of revenue. Bear Canyon Power Plant. The Bear Canyon Power Plant consists of a 20 megawatt geothermal power plant and associated steam fields located in northern California, two miles south of the West Ford Flat Power Plant. Electricity generated by the Bear Canyon Power Plant is sold to PG&E under two 10 megawatt power sales agreements terminating in 2008 which contain payment provisions for capacity and energy. During 1998, the Bear Canyon Power Plant generated approximately 176,508,000 kilowatt hours of electrical energy and approximately $20.4 million of revenue. Aidlin Power Plant. The Aidlin Power Plant consists of a 20 megawatt geothermal power plant and associated steam fields located in northern California. We hold an indirect 55% ownership interest in the Aidlin Power Plant. Electricity generated by the Aidlin Power Plant is sold to PG&E under two 10 megawatt power sales agreements terminating in 2009 which contain payment provisions for capacity and energy. During 1998, the Aidlin Power Plant generated approximately 170,046,000 kilowatt hours of electrical energy and revenue of $24.4 million. 54 59 PROJECT DEVELOPMENT AND ACQUISITIONS We are actively engaged in the development and acquisition of power generation projects. We have historically focused principally on the development and acquisition of interests in gas-fired and geothermal power projects, although we also consider projects that utilize other power generation technologies. We have significant expertise in a variety of power generation technologies and have substantial capabilities in each aspect of the development and acquisition process, including design, engineering, procurement, construction management, fuel and resource acquisition and management, financing and operations. ACQUISITIONS We will consider the acquisition of an interest in operating projects as well as projects under development where we would assume responsibility for completing the development of the project. In the acquisition of power generation facilities, we generally seek to acquire an ownership interest in facilities that offer us attractive opportunities for revenue and earnings growth, and that permit us to assume sole responsibility for the operation and maintenance of the facility. In evaluating and selecting a project for acquisition, we consider a variety of factors, including the type of power generation technology utilized, the location of the project, the terms of any existing power or thermal energy sales agreements, gas supply and transportation agreements and wheeling agreements, the quantity and quality of any geothermal or other natural resource involved, and the actual condition of the physical plant. In addition, we assess the past performance of an operating project and prepare financial projections to determine the profitability of the project. We generally seek to obtain a significant equity interest in a project and to obtain the operation and maintenance contract for that project. See "-- Strategy" and "Risk Factors -- Our power project development and acquisition activities may not be successful." We have grown substantially in recent years as a result of acquisitions of interests in power generation facilities and steam fields. We believe that although the domestic power industry is undergoing consolidation and that significant acquisition opportunities are available, we are likely to confront significant competition for acquisition opportunities. In addition, there can be no assurance that we will continue to identify attractive acquisition opportunities at favorable prices or, to the extent that any opportunities are identified, that we will be able to consummate such acquisitions. PENDING ACQUISITIONS COGENERATION CORPORATION OF AMERICA. On August 27, 1999 we announced an agreement with CGCA to acquire 80% of its common stock for $25.00 per share or approximately $145.0 million. NRG Energy, Inc., a wholly owned subsidiary of Northern States Power will own the remaining 20%. The transaction is subject to shareholder approval and we expect to consummate the acquisition by year-end 1999. CGCA currently owns interests in six natural gas-fired power plants, totaling 579 megawatts. The plants are located in Pennsylvania, New Jersey, Illinois and Oklahoma. As of June 30, 1999 CGCA had approximately $296.6 million of indebtedness, including $216.1 million of non-recourse project debt. Grays Ferry Power Plant. The Grays Ferry Power Plant is a 150 megawatt, natural gas-fired cogeneration project located in Philadelphia, Pennsylvania. CGCA owns 50% of the project and 50% is owned by Trigen Energy Corporation. The facility is operated by Trigen. Electricity generated by the Grays Ferry Power Plant is sold 55 60 under two long-term power sales agreements to PECO Energy Company, expiring in 2017. An affiliate of Trigen purchases the steam produced by the project pursuant to a 25-year contract expiring in 2022. Parlin Power Plant. The Parlin Power Plant consists of a 122 megawatt natural gas-fired cogeneration power plant located in Parlin, New Jersey. The facility is operated by NRG Energy, Inc. Electricity generated by the Parlin Power Plant is sold pursuant to a long-term contract expiring in 2011 to Jersey Central Power and Light Company ("JCP&L"), and steam produced is sold to E.I. Dupont de Nemours and Company under a long-term agreement expiring in 2021. Morris Power Plant. The Morris Power Plant consists of a 117 megawatt natural gas-fired cogeneration facility located in Morris, Illinois. The facility is operated by NRG Energy, Inc. Electricity and steam produced by the facility is sold to Equistar Chemicals, L.P. pursuant to a long-term contract expiring in 2023. Any surplus electricity is marketed to the Illinois power market. Pryor Power Plant. The Pryor Power Plant is a 110 megawatt natural gas-fired cogeneration power plant located in Pryor, Oklahoma. The facility is operated by NRG Energy, Inc. The Pryor Power Plant sells 100-megawatts of capacity and varying amounts of electrical energy to Oklahoma Gas and Electric under a contract expiring in 2007. Steam produced from the Pryor facility is sold to a number of industrial users under contracts with various termination dates ranging from 1998 to 2007. Surplus electricity is also sold to the Public Service of Oklahoma at its avoided cost. Newark Power Plant. The Newark Power Plant consists of a 58 megawatt natural gas-fired cogeneration power plant located in Newark, New Jersey. The facility is operated by NRG Energy, Inc. Electricity produced by the facility is sold pursuant to a long-term contract expiring in 2015 to JCP&L. Steam produced is sold to Newark Boxboard under a long-term contract expiring in 2015. Philadelphia Water Project. The Philadelphia Water Project consists of two standby peak shaving facilities located at the Philadelphia Water Department's Northeast and Southwest wastewater treatment plants. CGCA owns 83% of the project and the project is operated by O'Brien Energy Services Company. The project sells capacity and energy on demand to the Philadelphia Municipal Authority pursuant to two long-term contracts expiring in 2013. SHERIDAN ENERGY, INC. On August 25, 1999 we announced an agreement with Sheridan Energy, a natural gas exploration and production company, to acquire Sheridan Energy through a $41.0 million cash tender offer. We have offered to purchase all outstanding shares of Sheridan Energy's common stock for $5.50 per share. In addition, we have agreed to redeem $11.5 million of outstanding preferred stock of Sheridan Energy. We expect to complete the tender in October 1999. Sheridan Energy's oil and gas properties, including 148 billion cubic feet equivalent of proven reserves, are located in northern California and the Gulf Coast region, where we are developing low-cost natural gas supplies and proprietary pipeline systems to support our strategically-located natural gas-fired power plants. As of June 30, 1999, Sheridan Energy had indebtedness of $71.5 million. 56 61 PROJECT DEVELOPMENT The development of power generation projects involves numerous elements, including evaluating and selecting development opportunities, designing and engineering the project, obtaining power sales agreements, acquiring necessary land rights, permits and fuel resources, obtaining financing and managing construction. We intend to focus primarily on development opportunities where we are able to capitalize on our expertise in implementing an innovative and fully integrated approach to project development in which we control the entire development process. Utilizing this approach, we believe that we are able to enhance the value of our projects throughout each stage of development in an effort to maximize our return on investment. We are pursuing the development of highly efficient, low-cost power plants that seek to take advantage of inefficiencies in the electricity market. We intend to sell all or a portion of the power generated by such plants into the competitive market through a portfolio of short-, medium-and long-term power sales agreements. We expect that these projects will represent a prototype for our future plant developments. See "-- Strategy" and "Risk Factors -- 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 power sales agreements, governmental permits and approvals, fuel supply and transportation agreements, sufficient equity capital and debt financing, electrical transmission agreements, site agreements and construction contracts, and there can be no assurance that we will be successful in doing so. In addition, project development is subject to certain environmental, engineering and construction risks relating to cost-overruns, delays and performance. Although we may attempt to minimize the financial risks in the development of a project by securing a favorable long-term power sales agreement, entering into power marketing transactions, and obtaining all required governmental permits and approvals, the development of a power project may require us to expend significant sums for preliminary engineering, permitting and legal and other expenses before it can be determined whether a project is feasible, economically attractive or financeable. If we were unable to complete the development of a facility, we would generally not be able to recover our investment in such a facility. The process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. As a result of competition, it may be difficult to obtain a power sales agreement for a proposed project, and the prices offered in new power sales agreements for both electric capacity and energy may be less than the prices in prior agreements. We cannot assure that we will be successful in the development of power generation facilities in the future. Projects Under Construction Magic Valley Power Plant. In May 1998, we announced that we had signed a 20-year power sales agreement to provide electricity to the Magic Valley Electric Cooperative, Inc. of Mercedes, Texas beginning in 2001. The power will be supplied by our Magic Valley Generating Station, a 730 megawatt natural gas-fired power plant under development 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 57 62 wholesale customers, initially targeting south Texas. Construction commenced in April 1999 with commercial operations scheduled to begin in February 2001. Westbrook Power Plant. In February 1999, we acquired from Genesis Power Corporation ("Genesis"), a New England based power developer, the development rights to a 545 megawatt gas-fired combined-cycle power plant to be located in Westbrook, Maine. It is estimated that the development of the Westbrook Power Plant will cost approximately $300.0 million. Construction commenced in February 1999 and commercial operation is scheduled for early 2001. Upon completion, the Westbrook Power Plant will be operated by our company. It is anticipated that the output generated by the Westbrook Power Plant will be sold into the New England power market and to wholesale and retail customers in the northeastern United States. Pasadena Expansion. We are currently expanding the Pasadena Power Plant by an additional 545 megawatts. Construction began in November 1998 and commercial operation is expected to begin in June 2000. The electricity output from this expansion will be sold into the competitive market through our power sales activities. 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 545 megawatt gas-fired power plant on the tribe's reservation in Mojave County, Arizona. The electricity generated will be sold to the Arizona, Nevada and California power markets. Construction commenced in August 1999 and we anticipate that the South Point Power Plant will begin operation in March 2001. Sutter Power Plant. In February 1997, we announced plans to develop a 545 megawatt gas-fired combined cycle project in Sutter County, in northern California. The Sutter Power Plant would be northern California's first newly constructed power plant since deregulation of the California power market in 1998. Construction commenced in August 1999 and the Sutter Power Plant is expected to provide electricity to the deregulated California power market commencing in the year 2001. We are currently pursuing regulatory agency permits for this project. In January 1998, we announced that the Sutter Power Plant has met the California Energy Commission's Data Adequacy requirements in its Application for Certification. Tiverton Power Plant. In September 1998, we invested $40.0 million of equity in the development of a 265 megawatt gas-fired power plant to be located in Tiverton, Rhode Island. The Tiverton Power Plant is being developed by Energy Management Inc. ("EMI"). It is estimated that the development of the Tiverton Power Plant will cost approximately $172.5 million. For our investment in the Tiverton Power Plant, we will earn 62.8% of the Tiverton Power Plant project cash flow until a specified pre-tax return is reached, whereupon our company and EMI will share projected cash flows equally through the remaining life of the project. Construction commenced in late 1998 and commercial operation is currently scheduled for 2000. Upon completion, the Tiverton Power Plant will be operated by EMI and will sell its output in the New England power market and to wholesale and retail customers in the northeastern United States. Rumford Power Plant. In November 1998, we invested $40.0 million of equity in the development of a 265 megawatt gas-fired power plant to be located in Rumford, Maine. The Rumford Power Plant is being developed by EMI. It is estimated that the development of the Rumford Power Plant will cost approximately $160.0 million. For our 58 63 investment in the Rumford Power Plant, we will earn 66.7% of the Rumford Power Plant project cash flow until a specified pre-tax return is reached, whereupon our company and EMI will share projected cash flows equally through the remaining life of the project. Construction commenced in late 1998 and commercial operation is currently scheduled for 2000. Upon completion, the Rumford Power Plant will be operated by EMI and will sell its output in the New England power market and to wholesale and retail customers in the northeastern United States. Announced Development Projects Delta Energy Center. In February 1999, we, together with Bechtel Enterprises, announced plans to develop an 880 megawatt gas-fired cogeneration project in Pittsburg, California (the "Delta Energy Center"). The Delta Energy Center will provide steam and electricity to the nearby Dow Chemical Company facility and market the excess electricity into the California power market. We anticipate that construction will commence in early 2000 and that operation of the facility will commence in 2002. We are currently pursuing regulatory agency permits for this project. On February 3, 1999, our company and Bechtel announced that the Delta Energy Center has met the California Energy Commission's Data Adequacy requirements in its Application for Certification. Metcalf Energy Center. In February 1999, we, together with Bechtel Enterprises, announced plans to develop a 600 megawatt gas-fired cogeneration project in San Jose, California (the "Metcalf Energy Center"). We expect the California Energy Commission review, licensing and public hearing process will be completed by mid-2000. We anticipate that construction will commence following this approval and that commercial operation of the facility will commence in mid-2002. Electricity generated by the Metcalf Energy Center will be sold into the California power market. Pittsburg Power Plant. In August 1999, we entered into an agreement with Enron Capital & Trade Resources to acquire the development rights for a 550 megawatt natural gas-fired plant in Pittsburg, California. We expect to close the acquisition in 1999 upon receipt of the final permits. Construction is scheduled to commence in 1999 and commercial operations will begin in 2001. The facility is estimated to cost $350 million and will provide electricity and industrial steam totaling approximately 55 mw to USS Posco Industries under a long-term agreement. The balance of the plant's output will be sold into the California power market. 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 facility in Bastrop County, Texas. Construction of this facility is scheduled to begin in October 1999 and commercial operation in June 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. West Phoenix Power Plant. In April 1999, we announced an agreement with Pinnacle West Capital Corporation to develop a 545 megawatt gas-fired facility at Arizona Public Services West Phoenix Power Station in Phoenix, Arizona. Construction is scheduled to begin in mid-2000 with final completion in late 2002. The facility is estimated to cost $220 million and the electricity will be sold into the Arizona power market. 59 64 Ontelaunee Energy Center. In June 1999, we announced that we had acquired the rights to develop a 545 megawatt gas-fired power plant in Ontelaunee Township in eastern Pennsylvania. Permitting for the proposed $255 million facility is underway and construction is scheduled to begin in early 2000. Commercial operation is estimated for late 2002. Output from the plant will be sold into the Pennsylvania/New Jersey/Maryland (PJM) power pool and pursuant to bilateral contracts. GAS FIELDS 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. On July 25, 1997, Montis Niger, Inc. was renamed Calpine Gas Company. As of January 1, 1998, Calpine Gas Company had approximately 8.1 billion cubic feet of proven natural gas reserves and approximately 13,837 gross acres and 13,738 net acres under lease in the Sacramento Basin. In addition, Calpine Gas Company owns and operates an 80-mile pipeline delivering gas to the Greenleaf 1 and 2 Power Plants which had been either produced by Calpine Gas Company or purchased from third parties. Calpine Gas Company currently supplies approximately 79% of the fuel requirements for the Greenleaf 1 and 2 Power Plants. Sheridan. In January 1999, we announced that we had acquired a 20% interest in 82 billion cubic feet of proven natural gas reserves located in the Sacramento Basin in northern California. Sheridan Energy owns the remaining 80% interest in these reserves. In addition, we signed a 10-year agreement with Sheridan under which we will purchase all of Sheridan's Sacramento Basin production, which currently approximates 20,000 mmbtu per day. GOVERNMENT REGULATION We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of its energy generation facilities. Federal laws and regulations govern transactions by electrical and gas utility companies, the types of fuel which may be utilized by an electric generating plant, the type of energy which may be produced by such a plant and the ownership of a plant. State utility regulatory commissions must approve the rates and, in some instances, other terms and conditions under which public utilities purchase electric power from independent producers and sell retail electric power. Under certain circumstances where specific exemptions are otherwise unavailable, state utility regulatory commissions may have broad jurisdiction over non-utility electric power plants. Energy producing projects also are subject to federal, state and local laws and administrative regulations which govern the emissions and other substances produced, discharged or disposed of by a plant and the geographical location, zoning, land use and operation of a plant. Applicable federal environmental laws typically have both state and local enforcement and implementation provisions. These environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operate in compliance with such permits and approvals. 60 65 FEDERAL ENERGY REGULATION PURPA The enactment of the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA") and the adoption of regulations thereunder by FERC provided incentives for the development of cogeneration facilities and small power production facilities (those utilizing renewable fuels and having a capacity of less than 80 megawatts). A domestic electricity generating project must be a QF under FERC regulations in order to take advantage of certain rate and regulatory incentives provided by PURPA. PURPA exempts owners of QFs from the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions of the Federal Power Act (the "FPA") and, except under certain limited circumstances, state laws concerning rate or financial regulation. These exemptions are important to 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, state and local regulations that control the financial structure of an electric generating plant and the prices and terms on which electricity may be sold by the plant. Second, the FERC's regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs at a price based on the purchasing utility's "avoided cost," and that the utility sell back-up power to the QF on a non-discriminatory basis. The term "avoided cost" is defined as the incremental cost to an electric utility of electric energy or capacity, or both, which, but for the purchase from QFs, such utility would generate for itself or purchase from another source. The FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates lower than the utility's avoided costs. While public utilities are not explicitly required by PURPA to enter into long-term power sales agreements, PURPA helped to create a regulatory environment in which it has been common for long-term agreements to be negotiated. In order to be a QF, a cogeneration facility must produce not only electricity, but also useful thermal energy for use in an industrial or commercial process for heating or cooling applications in certain proportions to the facility's total energy output and must meet certain energy efficiency standards. A geothermal facility may qualify as a QF if it produces less than 80 megawatts of electricity. Finally, a QF (including a geothermal or hydroelectric QF or other qualifying small power producer) must not be controlled or more than 50% owned by an electric utility or by most electric utility holding companies, or a subsidiary of such a utility or holding company or any combination thereof. We endeavor to develop our projects, monitor compliance by the projects with applicable regulations and choose our customers in a manner which minimizes the risks of any project losing its QF status. Certain factors necessary to maintain QF status are, however, subject to the risk of events outside our control. For example, loss of a thermal energy customer or failure of a thermal energy customer to take required amounts of thermal energy from a cogeneration facility that is a QF could cause the facility to fail requirements regarding the level of useful thermal energy output. Upon the occurrence of such an event, we would seek to replace the thermal energy customer or find another use 61 66 for the thermal energy which meets PURPA's requirements, but no assurance can be given that this would be possible. If one of the facilities in which we have an interest should lose its status as a QF, the project would no longer be entitled to the exemptions from PUHCA and the FPA. This could 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 a public utility holding company by owning more than 10% of the voting securities of, or controlling, a facility that would no longer be exempt from PUHCA. This could cause all of our remaining projects to lose their qualifying status, because QFs may not be controlled or more than 50% owned by such public utility holding companies. Loss of QF status may also trigger defaults under covenants to maintain QF status in the projects' power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements such that loss of status may be on a retroactive or a prospective basis. Under the Energy Policy Act of 1992, if a facility can be qualified as an exempt wholesale generator ("EWG"), it will be exempt from PUHCA even if it does not qualify as a QF. Therefore, another response to the loss or potential loss of QF status would be to apply to have the project qualified as an EWG. However, assuming this changed status would be permissible under the terms of the applicable power sales agreement, rate approval from FERC 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. As a result, although such legislation may adversely affect our ability to develop new projects, we believe it would not affect our existing QFs. There can be no assurance, however, that any legislation passed would not adversely impact our existing projects. Public Utility Holding Company Regulation Under PUHCA, any corporation, partnership or other legal entity which owns or controls 10% or more of the outstanding voting securities of a "public utility company" or a company which is a "holding company" for a public utility company is subject to registration with the SEC and regulation under PUHCA, unless eligible for an exemption. A holding company of a public utility company that is subject to registration is required by PUHCA to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of that utility system. Approval by the SEC is required for nearly all important financial and business dealings of a registered holding company. Under PURPA, most QFs are not public utility companies under PUHCA. The Energy Policy Act of 1992, among other things, amends PUHCA to allow EWGs, under certain circumstances, to own and operate non-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 62 67 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 to develop such facilities which are not subject to the constraints of PUHCA. Federal Natural Gas Transportation Regulation We have an ownership interest in 19 gas-fired cogeneration projects. 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 operating of the gas pipeline); and obligations to take a minimum quantity of gas and pay for it (i.e., take-and-pay obligations). Pursuant to the Natural Gas Act, FERC has jurisdiction over the transportation and storage of natural gas in interstate commerce. With respect to most transactions that do not involve the construction of pipeline facilities, regulatory authorization can be obtained on a self-implementing basis. However, pipeline rates and terms and conditions for such services are subject to continuing FERC oversight. STATE REGULATION State public utility commissions ("PUCs") have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities 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 power purchase agreement with an independent power producer to the utility's retail customer. However, a regulatory commission under certain circumstances may disallow the full reimbursement to a utility for the cost to purchase power from a QF 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. In the State of California, restructuring legislation was enacted in September 1996 and was implemented in 1998. This legislation established an Independent Systems Operator ("ISO") responsible for centralized control and efficient and reliable operation of the state- 63 68 wide electric transmission grid, and a Power Exchange responsible for an efficient competitive electric energy auction open on a non-discriminatory basis to all electric services providers. Other provisions include the quantification and qualification of utility stranded costs to be eligible for recovery through competitive transition charges ("CTC"), market power mitigation through utility divestiture of fossil generation plants, the unbundling and establishment of rate structure for historical utility functions, the continuation of public purpose programs and issues related to issuance of rate reduction bonds. The California Energy Commission ("CEC") and Legislature have responsibility for development of a competitive market mechanism for allocation and distribution of funds made available by the legislation for enhancement of in-state renewable resource technologies and public interest research and development programs. Funds are to be available through the four-year transition period to a fully competitive electric services industry. In addition to the significant opportunity provided for power producers such as us through implementation of customer choice (direct access), the California restructuring legislation both recognizes the sanctity of existing contracts (including QF power sales contracts), provides for mitigation of utility horizontal market power through divestiture of fossil generation by California public utilities and provides funds for continuation of public services programs including fuel diversity through enhancement for in-state renewable technologies (includes geothermal) for the four-year transition period to a fully competitive electric services industry. Other states in which we conduct operations either have implemented or are actively considering similar restructuring legislation. State PUCs also have jurisdiction over the transportation of natural gas by local distribution companies ("LDCs"). Each state's regulatory laws are somewhat different; however, all generally require the LDC to obtain approval from the PUC for the construction of facilities and transportation services if the LDC's generally applicable tariffs do not cover the proposed transaction. LDC rates are usually subject to continuing PUC oversight. REGULATION OF CANADIAN GAS The Canadian natural gas industry is subject to extensive regulation by governmental authorities. At the federal level, a party exporting gas from Canada must obtain an export license from the Canadian National Energy Board ("NEB"). The NEB also regulates Canadian pipeline transportation rates and the construction of pipeline facilities. Gas producers also must obtain a removal permit or license from provincial authorities before natural gas may be removed from the province, and provincial authorities may regulate intra-provincial pipeline and gathering systems. In addition, a party importing natural gas into the United States first must obtain an import authorization from the U.S. Department of Energy. ENVIRONMENTAL REGULATIONS The exploration for and development of geothermal resources and the construction and operation of power projects are subject to extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to us primarily involve the discharge of emissions into the water and air and the use of water, but can also include wetlands preservation, endangered species, waste disposal and noise regulations. These laws and regulations in many cases 64 69 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. With respect to its Aidlin geothermal plant and one of its steam field pipelines, our operations have, in certain instances, necessitated variances under applicable California air pollution control laws. However, we believe that we are in material compliance with such laws with respect to such facilities. Clean Water Act The Federal Clean Water Act (the "Clean Water Act") establishes rules regulating the discharge of pollutants into waters of the United States. We are required to obtain a wastewater and storm water discharge permit for wastewater and runoff, respectively, from certain of our facilities. We believe that, with respect to our geothermal operations, we are exempt from newly promulgated federal storm water requirements. We believe that we are in material compliance with applicable discharge requirements under the Clean Water Act. Resource Conservation and Recovery Act The Resource Conservation and Recovery Act ("RCRA") regulates the generation, treatment, storage, handling, transportation and disposal of solid and hazardous waste. We believe that we are exempt from solid waste requirements under RCRA. However, particularly with respect to its solid waste disposal practices at the power generation facilities and steam fields located at The Geysers, we are subject to certain solid waste requirements under applicable California laws. We believe that our operations are in material compliance with such laws. Comprehensive Environmental Response, Compensation, and Liability Act The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ("CERCLA" or "Superfund"), requires cleanup of sites from which there has been a release or threatened release of hazardous substances and authorizes the 65 70 United States Environmental Protection Agency ("EPA") to take any necessary response action at Superfund sites, including ordering potentially responsible parties ("PRPs") liable for the release to take or pay for such actions. PRPs are broadly defined under CERCLA to include past and present owners and operators of, as well as generators of wastes sent to, a site. As of the present time, we are not subject to liability for any Superfund matters. However, we generate certain wastes, including hazardous wastes, and sends certain of our wastes to third-party waste disposal sites. As a result, there can be no assurance that we will not incur liability under CERCLA in the future. COMPETITION 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 which provide for direct access for all customers as of April 1, 1998. Regulatory initiatives are also being considered in other states, including Texas, New York and states in New England. See "Business -- Government Regulation -- State Regulation." This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the supply of electricity in the future will increase this pressure. EMPLOYEES As of August 31, 1999, we had 641 employees. None of our employees are covered by collective bargaining agreements, and we have never experienced a work stoppage, strike or labor dispute. We consider relations with our employees to be good. PROPERTIES Our principal executive office is located in San Jose, California, under a lease that expires in June 2001. We have leasehold interests in 105 leases comprising 19,813 acres of federal, state and private geothermal resource lands in The Geysers area in northern California. These leases comprise our West Ford Flat Power Plant, Bear Canyon Power Plant and certain steam fields. In the Glass Mountain and Medicine Lake areas in northern California, we hold leasehold interests in 20 leases comprising approximately 23,598 acres of federal geothermal resource lands. In general, under the leases, we have the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. The leases are generally for initial terms varying from 10 to 20 years or for so long as geothermal resources are produced and sold. Certain of the leases contain drilling or 66 71 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. We own 77 acres in Sutter County, California, on which the Greenleaf 1 Power Plant is located. We own Calpine Gas Company, which leases property covering approximately 13,837 gross acres and 13,738 net acres. See "-- Description of Facilities" for a description of the other material leased or owned properties in which we have an interest. We believe that our properties are adequate for our current operations. LEGAL PROCEEDINGS On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and certain other parties, including us. Some of Indeck's claims relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville Energy from Northern Hydro Limited and Calpine Auburndale, Inc.'s acquisition of a 50% interest in Auburndale Power Plant Partners Limited Partnership from Norweb Power Services (No. 1) Limited. Indeck is claiming that Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and Calpine Corporation tortiously interfered with Indeck's contractual rights to purchase such interests and conspired with other parties to do so. Indeck is seeking $25.0 million in compensatory damages, $25.0 million in punitive damages, and the recovery of attorneys' fees and costs. In July 1998, the court granted motions to dismiss, without prejudice, the claims against Calpine Gordonsville, Inc. and Calpine Auburndale, Inc. In August 1998, Indeck filed an amended complaint and the defendants filed motions to dismiss. We expect a hearing on the motions to be held in the near future. We are unable to predict the outcome of these proceedings but we do not believe that these proceedings will have a materially adverse effect on our financial results. An action was filed against Lockport Energy Associates ("LERA") and the New York Public Service Commission ("NYPSC") in August 1997 by New York State Electricity and Gas Company ("NYSEG") in the Federal District Court for the Northern District of New York. NYSEG has requested the Court to direct NYPSC and the Federal Energy Regulatory Commission (the "FERC") to modify contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that the FERC violated PURPA and the Federal Power Act by failing to reform the NYSEG contract that was previously approved by the NYPSC. Although we are unable to predict the outcome of this case, in any event, we retain the right to require The Brooklyn Union Gas Company to purchase our interest in the Lockport Power Plant for $18.9 million, less equity distributions received by us, at any time before December 19, 2001. We and our affiliates are involved in various other claims and legal actions arising out of the normal course of business. We do not expect that the outcome of these proceedings will have a material adverse effect on our financial position or results of operations, although we cannot assure you in this regard. 67 72 MANAGEMENT DIRECTORS AND EXECUTIVE OFFICERS The following table sets forth certain information with respect to our directors and executive officers.
NAME AGE POSITION ---- --- -------- Peter Cartwright.................... 69 Chairman of the Board, President, Chief Executive Officer and Director Ann B. Curtis....................... 48 Executive Vice President, Chief Financial Officer, Corporate Secretary and Director Jeffrey E. Garten................... 52 Director Susan C. Schwab..................... 44 Director George J. Stathakis................. 69 Director John O. Wilson...................... 61 Director V. Orville Wright................... 79 Director Thomas R. Mason..................... 55 Executive Vice President Robert D. Kelly..................... 41 Senior Vice President-Finance
Set forth below is certain information with respect to each director and executive officer. Peter Cartwright founded our company in 1984 and has served as a Director and as our President and Chief Executive Officer since inception. Mr. Cartwright became Chairman of our board of directors in September 1996. From 1979 to 1984, Mr. Cartwright was Vice President and General Manager of the Western Regional Office of Gibbs & Hill, Inc. ("Gibbs & Hill"), an architect-engineering firm that specialized in power engineering projects. From 1960 to 1979, Mr. Cartwright worked for General Electric's Nuclear Energy Division. His responsibilities included plant construction, project management and new business development. He served on the board of directors of nuclear fuel manufacturing companies in Germany, Italy and Japan. Mr. Cartwright was responsible for General Electric's technology development and licensing programs in Europe and Japan. Mr. Cartwright obtained a Master of Science Degree in Civil Engineering from Columbia University in 1953 and a Bachelor of Science Degree in Geological Engineering from Princeton University in 1952. Ann B. Curtis has served as Executive Vice President of our company since August 1998, and before that was our Senior Vice President since September 1992, and has been employed by us since our inception in 1984. Ms. Curtis became a Director of our company in September 1996. She is responsible for our financial and administrative functions, including the functions of general counsel, corporate and project finance, accounting, human resources, public relations and investor relations. Ms. Curtis also serves as our Chief Financial Officer and Corporate Secretary. From our inception in 1984 through 1992, she served as our Vice President for Management and Financial Services. Prior to joining our company, Ms. Curtis was Manager of Administration for the Western Regional Office of Gibbs & Hill. Jeffrey E. Garten became a Director of our company in January 1997. Mr. Garten has served as Dean of the Yale School of Management and William S. Beinecke Professor in the Practice of International Trade and Finance since November 1995. Mr. Garten served 68 73 as Undersecretary of Commerce of International Trade in the United States Department of Commerce from November 1993 to October 1995. From October 1990 to October 1992, Mr. Garten was a managing director of The Blackstone Group, an investment banking firm. Prior thereto, Mr. Garten founded and managed The Eliot Group, a small investment bank, from November 1987 to October 1990, and served as managing director of Lehman Brothers from January 1979 to November 1987. Susan C. Schwab became a Director of our company in January 1997. Dr. Schwab has served as Dean of the School of Public Affairs at the University of Maryland since August 1995. Dr. Schwab served as Director, Corporate Business Development at Motorola, Inc. from July 1993 to August 1995. She also served as Assistant Secretary of Commerce for the U.S. and Foreign Commercial Service from March 1989 to May 1993. George J. Stathakis became a Director of our company in September 1996 and has served as a Senior Advisor to us since December 1994. Mr. Stathakis has been providing financial, business and management advisory services to numerous corporations since 1985. He also served as Chairman of the Board and Chief Executive Officer of Ramtron International Corporation, an advanced technology semiconductor company, from 1990 to 1994. From 1986 to 1989, he served as Chairman of the Board and Chief Executive Officer of International Capital Corporation, a subsidiary of American Express. Prior to 1986, Mr. Stathakis served thirty-two years with General Electric Corporation in various management and executive positions. During his service with General Electric Corporation, Mr. Stathakis founded the General Electric Trading Company and was appointed its first President and Chief Executive. John O. Wilson became a Director of our company in January 1997. Mr. Wilson has served as a Senior Research Fellow at the Berkeley Roundtable on the International Economy and as Executive Vice President and Chief Economist of SDR Capital Management, Inc. since January 1999. Mr. Wilson served as Executive Vice President and Chief Economist at Bank of America from August 1984 to January 1999. He joined Bank of America in June 1975 as Director of Economics-Policy Research. He served as a faculty member at the University of California at Berkeley from September 1979 to June 1991, at the University of Connecticut from September 1974 to June 1975, and at Yale University from January 1967 to September 1970. Mr. Wilson also served as Director of Regulatory Analysis of the U.S. Atomic Energy Commission from April 1972 to October 1972, as Director of Welfare Reform of the Department of Health, Education and Welfare from April 1971 to April 1972, and as Assistant Director of the U.S. Office of Economic Opportunity from August 1969 to April 1971. V. Orville Wright became a Director of our company in January 1997. Mr. Wright served in various positions with MCI Communications Corp., including Vice Chairman and Co-Chief Executive Officer from 1988 to 1991, Vice Chairman and Chief Executive Officer from 1985 to 1987, and President and Chief Operating Officer from 1975 to 1985. Prior to 1975, Mr. Wright served in senior positions at Xerox Corp. from 1973 to 1975, at Amdahl Corporation from 1971 to 1973, at RCA from 1969 to 1971, and at IBM from 1949 to 1969. Thomas R. Mason has served as our Executive Vice President since August 1999 and Senior Vice President since March 1999 until August 1999. Mr. Mason is responsible for managing our power plant construction and operations activities. Prior to joining us, Mr. Mason was President and Chief Operating Officer of CalEnergy Operating Services Inc., a wholly owned subsidiary of MidAmerica Energy Holdings Company from 1995 to 69 74 February 1999. He obtained a Masters of Business Administration Degree from the University of Chicago in 1970 and a Bachelor of Science Degree in Electrical Engineering from Purdue University in 1966. Robert D. Kelly has served as our Senior Vice President-Finance since January 1998 and Vice President, Finance from April 1994 to January 1998. Mr. Kelly's responsibilities include all project and corporate finance activities. From 1992 to 1994, Mr. Kelly served as our Director-Project Finance, and from 1991 to 1992, he served as Project Finance Manager. Prior to joining us, he was the Marketing Manager of Westinghouse Credit Corporation from 1990 to 1991. From 1989 to 1990, Mr. Kelly was Vice President of Lloyds Bank PLC. From 1982 to 1989, Mr. Kelly was employed in various positions with The Bank of Nova Scotia. He obtained a Master of Business Administration Degree from Dalhousie University, Canada in 1980 and a Bachelor of Commerce Degree from Memorial University, Canada, in 1979. 70 75 PRINCIPAL STOCKHOLDERS The following table sets forth certain information known to us regarding beneficial ownership of our common stock as of August 31, 1999 by (1) each person known by us to be the beneficial owner of more than five percent of the outstanding shares of our common stock, (2) each of our directors, (3) certain of our executive officers and (4) all of our officers and directors as a group. All figures reflect the 2 for 1 stock split declared by us on September 20, 1999.
NAME AND ADDRESS NUMBER OF SHARES PERCENTAGE OF SHARES OF BENEFICIAL OWNER BENEFICIALLY OWNED(1) BENEFICIALLY OWNED(1) ------------------- --------------------- --------------------- Putnam Investments, Inc.................. 5,698,912 10.4% One Post Office Square Boston, MA 02109 Fidelity Management & Research Co........ 5,274,960 9.7% 82 Devonshire Street, E34E Boston, MA 02109 Ohio Public Employee Retirement System... 4,200,000 7.7% 277 East Town Street Columbus, OH 43215 Wellington Management Company, LLP....... 4,024,600 7.4% 75 State Street Boston, MA 02109 Peter Cartwright(2)...................... 2,011,604 3.6% Ann B. Curtis(3)......................... 534,008 * Thomas R. Mason.......................... 2,000 * Robert D. Kelly(4)....................... 243,320 * Jeffrey E. Garten(5)..................... 31,122 * Susan C. Schwab(5)....................... 29,848 * George J. Stathakis(6)................... 95,562 * John O. Wilson(5)........................ 37,348 * V. Orville Wright(7)..................... 45,960 * All executive officers and directors as a group (9 persons)(8)................... 3,030,772 5.3%
Footnotes appear on the next page. - ------------------------- * Less than one percent (1) This table is based in part upon information supplied by Schedules 13F filed by principal stockholders with the Securities and Exchange Commission (the "Commission"). Beneficial ownership is determined in accordance with the rules of the Commission and generally includes voting or investment power with respect to securities. Shares of common stock subject to options, warrants and convertible notes currently exercisable or convertible, or exercisable or convertible within 60 days after a specified date, are deemed outstanding for computing the percentage of the person holding such options but are not deemed outstanding for computing the percentage of any other person. Except as indicated by footnote, and subject to community property laws where applicable, the persons named in the table have sole voting and investment power with respect to all 71 76 shares of common stock shown as beneficially owned by them. The number of shares of common stock outstanding as of August 31, 1999 was 54,569,788. (2) Includes options to purchase 1,999,704 shares of our common stock issuable upon the exercise of options outstanding as of August 31, 1999 or within 60 days thereafter. (3) Includes options to purchase 533,382 shares of our common stock issuable upon the exercise of options outstanding as of August 31, 1999 or within 60 days thereafter. (4) Includes options to purchase 240,720 shares of our common stock issuable upon the exercise of options outstanding as of August 31, 1999 or within 60 days thereafter. (5) Represents shares of our common stock issuable upon exercise of options that are exercisable as of August 31, 1999 or will become exercisable within 60 days thereafter. (6) Includes options to purchase 89,562 shares of our common stock issuable upon the exercise of options outstanding as of August 31, 1999 or within 60 days thereafter. (7) Includes options to purchase 35,960 shares of our common stock issuable upon the exercise of options outstanding as of August 31, 1999 or within 60 days thereafter. (8) Includes options to purchase 3,184,270 shares of our common stock issuable upon the exercise of options outstanding as of August 31, 1999 or within 60 days thereafter. 72 77 DESCRIPTION OF CAPITAL STOCK Our authorized capital stock consists of 100,000,000 shares of common stock, $.001 par value, and 10,000,000 shares of preferred stock, $.001 par value. The following summary is qualified in its entirety by the provisions of our certificate of incorporation and bylaws, which have been filed as exhibits to the Registration Statement of which this prospectus constitutes a part. The information provided below reflects the 2 for 1 stock split declared by us on September 20, 1999. COMMON STOCK There will be 60,569,788 shares of common stock outstanding upon the completion of this offering, based on the 54,569,788 shares outstanding as of September 10, 1999. The holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Subject to preferences that may be applicable to any outstanding preferred stock, the holders of common stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the board of directors out of funds legally available therefor. See "Dividend Policy." In the event of our liquidation, dissolution or winding up, the holders of common stock are entitled to share ratably in all assets remaining after payment of liabilities, subject to prior liquidation rights of preferred stock, if any, then outstanding. The common stock has no preemptive or conversion rights or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of common stock to be outstanding upon the completion of the common stock offering will be fully paid and non-assessable. PREFERRED STOCK The board of directors has the authority to issue the preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions granted to or imposed upon any wholly unissued shares of undesignated preferred stock and to fix the number of shares constituting any series and the designations of such series, without any further vote or action by the stockholders. The board of directors, without stockholder approval, can issue preferred stock with voting and conversion rights which could adversely affect the voting power of the holders of common stock. The issuance of preferred stock may have the effect of delaying, deferring or preventing a change in control of our company, or could delay or prevent a transaction that might otherwise give our stockholders an opportunity to realize a premium over the then prevailing market price of the common stock. There will be no shares of preferred stock outstanding upon the completion of the common stock offering. ANTI-TAKEOVER EFFECTS OF PROVISIONS OF THE CERTIFICATE OF INCORPORATION, BYLAWS AND DELAWARE LAW CERTIFICATE OF INCORPORATION AND BYLAWS Our certificate of incorporation and bylaws provide that our board of directors is classified into three classes of Directors serving staggered, three-year terms. The certificate of incorporation also provides that Directors may be removed only by the affirmative vote of the holders of two-thirds of the shares of our capital stock entitled to vote. Any vacancy on the board of directors may be filled only by vote of the majority of Directors then in office. Further, the certificate of incorporation provides that any "Business Combination" 73 78 (as therein defined) requires the affirmative vote of the holders of two-thirds of the shares of our capital stock entitled to vote, voting together as a single class. The certificate of incorporation also provides that all stockholder actions must be effected at a duly called meeting and not by a consent in writing. The bylaws provide that our stockholders may call a special meeting of stockholders only upon a request of stockholders owning at least 50% of our capital stock. These provisions of the certificate of incorporation and bylaws could discourage potential acquisition proposals and could delay or prevent a change in control of our company. These provisions are intended to enhance the likelihood of continuity and stability in the composition of the board of directors and in the policies formulated by the board of directors and to discourage certain types of transactions that may involve an actual or threatened change of control of our company. These provisions are designed to reduce our vulnerability to an unsolicited acquisition proposal. The provisions also are intended to discourage certain tactics that may be used in proxy fights. However, such provisions could have the effect of discouraging others from making tender offers for our shares and, as a consequence, they also may inhibit fluctuations in the market price of our shares that could result from actual or rumored takeover attempts. Such provisions also may have the effect of preventing changes in our management. DELAWARE ANTI-TAKEOVER STATUTE We are subject to Section 203 of the Delaware General Corporation Law ("Section 203"), which, subject to certain exceptions, prohibits a Delaware corporation from engaging in any business combination with any interested stockholder for a period of three years following the date that such stockholder became an interested stockholder, unless: (1) prior to such date, the board of directors of the corporation approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder; (2) upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the number of shares outstanding those shares owned (x) by persons who are directors and also officers and (y) by employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or (3) on or subsequent to such date, the business combination is approved by the board of directors and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder. Section 203 defines business combination to include: (1) any merger or consolidation involving the corporation and the interested stockholder; (2) any sale, transfer, pledge or other disposition of 10% or more of the assets of the corporation involving the interested stockholder; (3) subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any stock of the corporation to the interested stockholder; (4) any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder; or (5) the receipt by the interested stockholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation. In general, Section 203 defines an interested stockholder as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by such entity or person. 74 79 UNDERWRITING Under the terms and subject to the conditions contained in an underwriting agreement dated , 1999, we have agreed to sell to the underwriters named below, for whom Credit Suisse First Boston Corporation, are acting as representatives, the following respective numbers of shares of common stock:
Number Underwriter of Shares ----------- --------- Credit Suisse First Boston Corporation.......................... --------- Total................................................. 6,000,000 =========
The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering of common stock may be terminated. We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to 900,000 additional shares at the public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock. The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a concession of $ per share. The underwriters and selling group members may allow a discount of $ per share on sales to other broker/dealers. After the public offering, the public offering price and concession and discount to broker/dealers may be changed by the representatives. The following table summarizes the compensation and estimated expenses we will pay.
PER SHARE TOTAL ------------------------------- ------------------------------- WITHOUT WITH WITHOUT WITH OVER-ALLOTMENT OVER-ALLOTMENT OVER-ALLOTMENT OVER-ALLOTMENT -------------- -------------- -------------- -------------- Underwriting Discounts and Commissions paid by us... Expenses payable by us.....
We and each of our officers and directors have agreed that we will not offer, sell, contract to sell, announce our intention to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act of 1933 relating to any additional shares of our common stock or securities convertible into or 75 80 exchangeable or exercisable for any of our common stock, or publicly disclose the intention to make an offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse First Boston Corporation for a period of 90 days after the date of this prospectus, except in our case issuances pursuant to the exercise of employee stock options outstanding on the date hereof. We have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments which the underwriters may be required to make in that respect. Credit Suisse First Boston, New York branch expects to be the lead arranger and a lender for our proposed $1.0 billion revolving construction loan facility and, in such capacity, expects to receive customary fees for such services. The representatives may engage in over-allotment, stabilizing transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934. - Over-allotment involves syndicate sales in excess of the offering size, which creates a syndicate short position. Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. - Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. - Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by such syndicate member is purchased in a syndicate covering transaction to cover syndicate short positions. These stabilizing transactions, syndicate covering transactions and penalty bids may cause the price of the common stock to be higher than it would otherwise be in the absence of such transactions. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time. From time to time, certain of the underwriters have provided advisory and investment banking services to us, for which customary compensation has been received. It is expected that such underwriters will continue to provide such services to us in the future. NOTICE TO CANADIAN RESIDENTS RESALE RESTRICTIONS The distribution of the common stock in Canada is being made only on a private placement basis exempt from the requirement that we prepare and file a prospectus with the securities regulatory authorities in each province where trades of common stock are effected. Accordingly, any resale of the common stock in Canada must be made in accordance with applicable securities law which will vary depending on the relevant jurisdiction, and which may require resales to be made in accordance with available statutory exemptions or pursuant to a discretionary exemption granted by the applicable 76 81 Canadian securities regulatory authority. Purchasers are advised to seek legal advice prior to any resale of the common stock. REPRESENTATIONS OF PURCHASERS Each purchaser of common stock in Canada who receives a purchase confirmation will be deemed to represent to us and the dealer from whom such purchase confirmation is received that (1) such purchaser is entitled under applicable provincial securities laws to purchase such common stock without the benefit of a prospectus qualified under such securities laws, (2) where required by law, that such purchaser is purchasing as principal and not as agent, and (3) such purchaser has reviewed the text above under "Resale Restrictions". RIGHTS OF ACTION (ONTARIO PURCHASERS) The securities being offered are those of a foreign issuer and Ontario purchasers will not receive the contractual right of action prescribed by Ontario securities law. As a result, Ontario purchasers must rely on other remedies that may be available, including common law rights of action for damages or rescission or rights of action under the civil liability provisions of the U.S. federal securities laws. ENFORCEMENT OF LEGAL RIGHTS All of the issuer's directors and officers as well as the experts named herein may be located outside of Canada and, as a result, it may not be possible for Canadian purchasers to effect service of process within Canada upon the issuer or such persons. All or a substantial portion of the assets of the issuer and such persons may be located outside of Canada and, as a result, it may not be possible to satisfy a judgment against the issuer or such persons in Canada or to enforce a judgment obtained in Canadian courts against such issuer or persons outside of Canada. NOTICE TO BRITISH COLUMBIA RESIDENTS A purchaser of common stock to whom the Securities Act (British Columbia) applies is advised that such purchaser is required to file with the British Columbia Securities Commission a report within ten days of the sale of any common stock acquired by such purchaser pursuant to this offering. Such report must be in the form attached to British Columbia Securities Commission Blanket Order BOR #95/17, a copy of which may be obtained from us. Only one such report must be filed in respect of common stock acquired on the same date and under the same prospectus exemption. TAXATION AND ELIGIBILITY FOR INVESTMENT Canadian purchasers of common stock should consult their own legal and tax advisors with respect to the tax consequences of an investment in the common stock in their particular circumstances and with respect to the eligibility of the common stock for investment by the purchaser under relevant Canadian legislation. 77 82 LEGAL MATTERS The validity of the securities offered hereby will be passed upon for us by Brobeck, Phleger & Harrison LLP, San Francisco, California. The underwriters have been represented by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York. EXPERTS The consolidated financial statements and schedules as of December 31, 1998, 1997 and 1996 incorporated by reference in this prospectus and elsewhere in the registration statement have been audited by Arthur Andersen LLP, independent public accountants, as set forth in their reports. In those reports, that firm states that with respect to Sumas Cogeneration Company, L.P. its opinion is based on the reports of other independent public accountants, namely Moss Adams LLP. The consolidated financial statements and supporting schedules referred to above have been included herein in reliance upon the authority of that firm as experts in giving said reports. The consolidated financial statements of Sumas Cogeneration Company, L.P. and Subsidiary as of December 31, 1998 and 1997 and for each of the years ended December 31, 1998, 1997 and 1996 included in our Annual Report on Form 10-K as amended filed with the Securities and Exchange Commission on February 18, 1999 and incorporated by reference in this prospectus have been audited by Moss Adams LLP, independent public accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon authority of said firm as experts in giving said reports. 78 83 PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION The following table sets forth the costs and expenses, other than underwriting discounts and commissions, payable by Calpine in connection with the sale of common stock being registered. All amounts are estimates except the SEC registration fee. SEC Registration Fee........................................ $ 86,499 NASD Filing Fee............................................. $ 30,500 Legal Fees and Expenses..................................... * Accounting Fees and Expenses................................ * Printing Fees............................................... * Transfer Agent fees......................................... * Miscellaneous............................................... * -------- Total............................................. * ========
- ------------------------- * To be supplied by amendment ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS Section 145 of the General Corporation Law of the state of Delaware (the "Delaware Law") empowers a Delaware corporation to indemnify any persons who are, or are threatened to be made, parties to any threatened, pending or completed legal action, suit or proceedings, whether civil, criminal, administrative or investigative (other than action by or in the right of such corporation), by reason of the fact that such person was an officer or director of such corporation, or is or was serving at the request of such corporation as a director, officer, employee or agent of another corporation or enterprise. The indemnity may include expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided that such officer or director acted in good faith and in a manner he reasonably believed to be in or not opposed to the corporation's best interests, and, for criminal proceedings, had no reasonable cause to believe his conduct was illegal. A Delaware corporation may indemnify officers and directors in an action by or in the right of the corporation under the same conditions, except that no indemnification is permitted without judicial approval if the officer or director is adjudged to be liable to the corporation in the performance of his duty. Where an officer or director is successful on the merits or otherwise in the defense of any action referred to above, the corporation must indemnify him against the expenses which such officer or director actually and reasonably incurred. In accordance with Delaware Law, the certificate of incorporation of the Company contains a provision to limit the personal liability of the directors of the Registrant for violations of their fiduciary duty. This provision eliminates each director's liability to the Registrant or its stockholders for monetary damages except (i) for any breach of the director's duty of loyalty to the Registrant or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the Delaware Law providing for liability of directors for unlawful payment of dividends or unlawful stock purchases or redemptions, or (iv) for any transaction from which a director derived an improper personal benefit. The effect of this II-1 84 provision is to eliminate the personal liability of directors for monetary damages for actions involving a breach of their fiduciary duty of care, including any such actions involving gross negligence. Article Ten of the bylaws of the Registrant provides for indemnification of the officers and directors of the Registrant to the fullest extent permitted by applicable law. We have entered into indemnification agreements with our directors and officers. These agreements provide substantially broader indemnity rights than those provided under the Delaware Law and the Company's bylaws. The indemnification agreements are not intended to deny or otherwise limit third-party or derivative suits against the Company or its directors or officers, but if a director or officer were entitled to indemnity or contribution under the indemnification agreement, the financial burden of a third-party suit would be borne by the Company, and the Company would not benefit from derivative recoveries against the director or officer. Such recoveries would accrue to the benefit of the Company but would be offset by the Company's obligations to the director or officer under the indemnification agreement. ITEM 16. EXHIBITS
EXHIBIT NUMBER DESCRIPTION - ------- ----------- *1.1 Form of Underwriting Agreement (Common Stock) +3.1 Amended and restated Certificate of Incorporation of Calpine Corporation, a Delaware corporation(a) +3.2 Amended and restated By-laws of Calpine Corporation, a Delaware corporation(a) +4.1 Indenture dated as of February 17, 1994 between the Company and Shawmut Bank of Connecticut, National Association, as Trustee, including form of Notes(b) +4.2 Indenture dated as of May 16, 1996 between the Company and Fleet National Bank, as Trustee, including form of Notes(c) +4.3 Indenture dated as of July 8, 1997 between the Company and The Bank of New York, as Trustee, including form of Notes(d) +4.4 Indenture dated as of March 31, 1998 between the Company and The Bank of New York, as Trustee, including form of Senior Notes(e) +4.5 Indenture dated as of March 26, 1999 between the Company and The Bank of New York, as Trustee, including the form of Senior Notes(f) +4.6 Indenture dated as of April 21, 1999 between the Company and The Bank of New York, as Trustee, including the form of Senior Notes(f) *5.1 Opinion of Brobeck, Phleger & Harrison LLP 23.1 Consent of Arthur Andersen LLP, independent public accountants 23.2 Consent of Moss Adams LLP, independent public accountants *23.3 Consent of Brobeck, Phleger & Harrison LLP (included in Exhibit 5.1) 24.1 Powers of Attorney (included in the signature page of this Registration Statement)
II-2 85 - ------------------------- * To be filed by amendment. + Previously filed. (a) Incorporated by reference to registrant's Registration Statement on Form S-1 (Registration Statement 33-07497) (b) Incorporated by reference to registrant's Registration Statement on Form S-1 (Registration Statement No. 33-73160) (c) Incorporated by reference to registrant's Current Report on Form 8-K dated August 29, 1996 and filed on September 13, 1996. (d) Incorporated by reference to registrant's Quarterly Report on Form 10-Q dated June 30, 1997 and filed on August 14, 1997. (e) Incorporated by reference to registrant's Registration Statement on Form S-4 (Registration Statement No. 333-61047) (f) Incorporated by reference to registrant's Registration Statement on Form S-3 (Registration Statement No. 333-72583) ITEM 17. UNDERTAKINGS The undersigned registrant hereby undertakes: (1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement: (i) to include any prospectus required by Section 10(a)(3) of the Securities Act; (ii) to reflect in the prospectus any facts or events arising after the effective date of the registration statement, or the most recent post-effective amendment thereof, which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement; and (iii) to include any material information with respect to the plan of distribution not previously disclosed in the Registration Statement or any material change to such information in the registration statement. (2) That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. (3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and therefore is unenforceable. In the event that a claim for indemnification against such liabilities, other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any II-3 86 action, suit or proceeding is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. The undersigned registrant hereby undertakes that, for purposes of determining any liability under the Securities Act, each filing of the registrant's annual report pursuant to Section 13(a) or Section 15(d) of the Exchange Act, and, where applicable, each filing of an employee benefit plan's annual report pursuant to Section 15(d) of the Exchange Act, that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. II-4 87 SIGNATURES Pursuant to the requirements of the Securities Act of 1933 the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-3 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized in the City of San Jose, State of California, on this 20th day of September, 1999. CALPINE CORPORATION By /s/ PETER CARTWRIGHT ------------------------------------ Peter Cartwright Chairman, President, Chief Executive Officer and Director KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Peter Cartwright and Ann B. Curtis, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement, and to file same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and any of them, or their or his substitutes, may lawfully do or cause to be done by virtue thereof. Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons on behalf of Calpine and in the capacities and on the dates indicated:
SIGNATURE TITLE DATE --------- ----- ---- /s/ PETER CARTWRIGHT Chairman, President, September 20, 1999 - --------------------------------------------- Chief Executive Officer, Peter Cartwright and Director (Principal Executive Officer) /s/ ANN B. CURTIS Executive Vice President September 20, 1999 - --------------------------------------------- and Director Ann B. Curtis (Principal Financial and Accounting Officer) /s/ JEFFREY E. GARTEN Director September 20, 1999 - --------------------------------------------- Jeffrey E. Garten /s/ SUSAN C. SCHWAB Director September 20, 1999 - --------------------------------------------- Susan C. Schwab /s/ GEORGE J. STATHAKIS Director September 20, 1999 - --------------------------------------------- George J. Stathakis /s/ JOHN O. WILSON Director September 20, 1999 - --------------------------------------------- John O. Wilson /s/ V. ORVILLE WRIGHT Director September 20, 1999 - --------------------------------------------- V. Orville Wright
II-5 88 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION - ------- ----------- *1.1 Form of Underwriting Agreement (Common Stock) +3.1 Amended and restated Certificate of Incorporation of Calpine Corporation, a Delaware corporation(a) +3.2 Amended and restated By-laws of Calpine Corporation, a Delaware corporation(a) +4.1 Indenture dated as of February 17, 1994 between the Company and Shawmut Bank of Connecticut, National Association, as Trustee, including form of Notes(b) +4.2 Indenture dated as of May 16, 1996 between the Company and Fleet National Bank, as Trustee, including form of Notes(c) +4.3 Indenture dated as of July 8, 1997 between the Company and The Bank of New York, as Trustee, including form of Notes(d) +4.4 Indenture dated as of March 31, 1998 between the Company and The Bank of New York, as Trustee, including form of Senior Notes(e) +4.5 Indenture dated as of March 26, 1999 between the Company and The Bank of New York, as Trustee, including the form of Senior Notes(f) +4.6 Indenture dated as of April 21, 1999 between the Company and The Bank of New York, as Trustee, including the form of Senior Notes(f) *5.1 Opinion of Brobeck, Phleger & Harrison LLP 23.1 Consent of Arthur Andersen LLP, independent accountants 23.2 Consent of Moss Adams LLP, independent accountants *23.3 Consent of Brobeck, Phleger & Harrison LLP (included in Exhibit 5.1) 24.1 Powers of Attorney (included in the signature page of this Registration Statement)
- ------------------------- * To be filed by amendment. + Previously filed. (a) Incorporated by reference to registrant's Registration Statement on Form S-1 (Registration Statement 33-07497) (b) Incorporated by reference to registrant's Registration Statement on Form S-1 (Registration Statement No. 33-73160) (c) Incorporated by reference to registrant's Current Report on Form 8-K dated August 29, 1996 and filed on September 13, 1996. (d) Incorporated by reference to registrant's Quarterly Report on Form 10-Q dated June 30, 1997 and filed on August 14, 1997. (e) Incorporated by reference to registrant's Registration Statement on Form S-4 (Registration Statement No. 333-61047) (f) Incorporated by reference to registrant's Registration Statement on Form S-3 (Registration Statement No. 333-72583) EX-23.1 2 CONSENT OF ARTHUR ANDERSEN LLP 1 EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference in this registration statement of our reports dated February 5, 1999 in Calpine Corporation's Form 10-K for the year ended December 31, 1998 and to all references to our Firm included in this registration statement. ARTHUR ANDERSEN LLP September 20, 1999 EX-23.2 3 CONSENT OF MOSS ADAMS LLP 1 EXHIBIT 23.2 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS We consent to the incorporation by reference in this Registration Statement on Form S-3 of Calpine Corporation for the registration of 6,900,000 shares of its common stock of our report of Sumas Cogeneration Company, L.P. and Subsidiary dated January 20, 1999, on our audits of the consolidated financial statements of Sumas Cogeneration Company, L.P. and Subsidiary as of December 31, 1998 and 1997, and for each of the three years ended December 31, 1998, which report is included in Calpine Corporation's 1998 Annual Report on Form 10-K, filed with the Securities and Exchange Commission. We also consent to the reference to our firm under the caption "Experts." MOSS ADAMS LLP Everett, Washington September 20, 1999 -----END PRIVACY-ENHANCED MESSAGE-----