-----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, RfadUpQ3PMfJPn3yn5bEfCpARiT3HrNw3f7BWhjaMNUuWXV9JVIm4zIANi4nw0RO 71iccxhFc89/L5SMwLeGDg== 0000916457-99-000009.txt : 19990813 0000916457-99-000009.hdr.sgml : 19990813 ACCESSION NUMBER: 0000916457-99-000009 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 19990812 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: 10-Q SEC ACT: SEC FILE NUMBER: 001-12079 FILM NUMBER: 99685502 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 10-Q 1 CALPINE CORPORATION 2ND QTR FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 _____________________ FORM 10-Q [ X ] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarter ended June 30, 1999 [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from ______________________ to ______________________ Commission File Number: 033-73160 CALPINE CORPORATION (A Delaware Corporation) I.R.S. Employer Identification No. 77-0212977 50 West San Fernando Street San Jose, California 95113 Telephone: (408) 995-5115 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ] Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of the latest practicable date: $0.001 par value Common Stock 27,174,147 shares outstanding on August 2, 1999. CALPINE CORPORATION AND SUBSIDIARIES Report on Form 10-Q For the Three and Six Months Ended June 30, 1999 INDEX PART I. FINANCIAL INFORMATION Page No. ITEM 1. Financial Statements Consolidated Balance Sheets June 30, 1999 and December 31, 1998 ............................... 3 Consolidated Statements of Operations Three and Six Months Ended June 30, 1999 and 1998 ................. 4 Consolidated Statements of Cash Flows Six Months Ended June 30, 1999 and 1998 ........................... 5 Notes to Consolidated Financial Statements ........................ 6 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations ...................... 15 PART II..OTHER INFORMATION ITEM 1. Legal Proceedings ........................................ 29 ITEM 2. Change in Securities ..................................... 30 ITEM 3. Quantitative and Qualitative Disclosures about Market Risk......................................... 30 ITEM 4. Submission of Matters to a Vote of Security Holders ...... 30 ITEM 5. Other Information ........................................ 30 ITEM 6. Exhibits and Reports on Form 8-K ......................... 30 Signatures ................................................................. 33 2 ITEM 1. FINANCIAL STATEMENTS CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS June 30, 1999 and December 31, 1998 (in thousands)
June 30, December 31, 1999 1998 ---------- ------------ (unaudited) ASSETS Current assets: Cash and cash equivalents ............................ $ 320,287 $ 96,532 Accounts receivable from related parties ............. 1,745 4,115 Accounts receivable .................................. 116,845 79,743 Inventories .......................................... 14,504 14,194 Other current assets ................................. 20,428 14,919 ---------- ---------- Total current assets ......................... 473,809 209,503 ---------- ---------- Property, plant and equipment, net ..................... 1,568,882 1,094,303 Investments in power projects .......................... 234,584 221,509 Project development costs .............................. 49,563 17,001 Collateral securities, net of current portion .......... 84,818 86,920 Notes receivable from related parties .................. 16,202 10,899 Restricted cash ........................................ 38,719 14,454 Deferred financing costs ............................... 30,091 22,789 Other assets ........................................... 53,082 51,568 ---------- ---------- Total assets ................................. $2,549,750 $1,728,946 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Non-recourse project financing, current portion ...... $ -- $ 5,450 Accounts payable ..................................... 44,070 53,190 Accrued interest payable ............................. 37,623 25,600 Other current liabilities ............................ 45,687 38,339 ---------- ---------- Total current liabilities .................... 127,380 122,579 ---------- ---------- Construction financing ................................. 79,210 -- Non-recourse project financing, net of current portion.. -- 114,190 Senior notes ........................................... 1,551,750 951,750 Deferred income taxes, net ............................. 173,072 159,788 Deferred lease incentive ............................... 66,029 67,814 Other liabilities ...................................... 38,182 25,859 ---------- ---------- Total liabilities ............................ 2,035,623 1,441,980 ---------- ---------- Stockholders' equity: Preferred stock, $0.001 par value per share: authorized 10,000,000 shares, none issued and outstanding in 1999 and 1998 .................... -- -- Common stock, $0.001 par value per share: authorized 100,000,000 shares; issued and outstanding 27,174,147 in 1999 and 20,161,581 in 1998 .................................. 27 20 Additional paid-in capital ........................... 374,618 168,874 Retained earnings .................................... 139,482 118,072 ---------- ---------- Total stockholders' equity ................... 514,127 286,966 ---------- ---------- Total liabilities and stockholders' equity ... $2,549,750 $1,728,946 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 3 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENT OF OPERATIONS For the Three and Six Months Ended June 30, 1999 and 1998 (in thousands, except per share amounts) (unaudited)
Three Months Ended Six Months Ended June 30, June 30, -------------------- -------------------- 1999 1998 1999 1998 --------- --------- --------- --------- Revenue: Electricity and steam sales ....... $ 176,296 $ 135,408 $ 304,322 $ 178,798 Service contract revenue .......... 6,466 3,048 13,238 8,529 Income from unconsolidated investments in power projects .... 7,509 3,099 18,321 6,853 Interest income on loans to power projects ................ 406 42 709 2,562 --------- --------- --------- --------- Total revenue ............... 190,677 141,597 336,590 196,742 --------- --------- --------- --------- Cost of revenue: Plant operating expenses .......... 26,648 18,565 49,784 28,837 Fuel expense ...................... 61,521 52,164 115,458 57,835 Depreciation ...................... 23,310 18,461 42,289 30,811 Production royalties .............. 3,209 2,366 5,626 5,238 Operating lease expenses .......... 7,959 3,308 13,552 6,616 Service contract expenses ......... 6,016 1,892 11,461 6,788 --------- --------- --------- --------- Total cost of revenue ...... 128,663 96,756 238,170 136,125 --------- --------- --------- --------- Gross profit ....................... 62,014 44,841 98,420 60,617 Project development expenses ....... 2,292 1,438 4,248 3,119 General & administrative expenses .. 10,933 5,807 20,964 11,043 --------- --------- --------- --------- Income from operations ........ 48,789 37,596 73,208 46,455 Other expense (income): Interest expense .................. 26,144 22,267 47,171 40,790 Interest income ................... (7,054) (3,332) (9,832) (5,695) Other income, net ................. (1,073) (503) (1,236) (904) --------- --------- --------- --------- Income before provision for income taxes ............... 30,772 19,164 37,105 12,264 Provision for income taxes ......... 12,062 7,236 14,545 3,393 --------- --------- --------- --------- Income before extraordinary charge 18,710 11,928 22,560 8,871 Extraordinary charge, net of tax benefit of $793 and $207 ......... 1,150 302 1,150 302 --------- --------- --------- --------- Net income .................... $ 17,560 $ 11,626 $ 21,410 $ 8,569 ========= ========= ========= ========= Basic earnings per common share: Weighted average shares outstanding 26,923 20,105 23,759 20,056 Income before extraordinary charge $ 0.69 $ 0.59 $ 0.95 $ 0.44 Extraordinary charge .............. $ (0.04) $ (0.01) $ (0.05) $ (0.01) Net income ........................ $ 0.65 $ 0.58 $ 0.90 $ 0.43 Diluted earnings per common share: Weighted average shares outstanding 28,524 21,126 25,235 21,050 Income before extraordinary charge $ 0.66 $ 0.56 $ 0.89 $ 0.42 Extraordinary charge .............. $ (0.04) $ (0.01) $ (0.04) $ (0.01) Net income ........................ $ 0.62 $ 0.55 $ 0.85 $ 0.41
The accompanying notes are an integral part of these consolidated financial statements. 4 CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 1999 and 1998 (in thousands) (unaudited)
Six Months Ended June 30, ---------------------- 1999 1998 --------- --------- Cash flows from operating activities: Net income ...................................... $ 21,410 $ 8,569 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization .................. 44,086 31,428 Deferred income taxes, net ..................... 13,285 2,374 Income from unconsolidated investments in power projects ............................. (18,321) (6,853) Distributions from unconsolidated power projects 25,522 12,995 Change in operating assets and liabilities: Accounts receivable .......................... (34,503) (6,486) Inventories ................................. 440 327 Other current assets ......................... 3,258 6,961 Other assets ................................. (3,794) (5,967) Accounts payable and accrued expenses ........ 10,037 (23,245) Other liabilities ............................ (2,865) 2,970 --------- --------- Net cash provided by operating activities .. 58,555 23,073 --------- --------- Cash flows from investing activities: Acquisition of property, plant and equipment .... (423,874) (23,983) Acquisitions .................................... (117,824) (160,517) Proceeds from sale and leaseback of plant ....... 18,436 -- Decrease (increase) in notes receivable ......... (5,303) 13,814 Maturities of collateral securities ............. 1,850 6,030 Project development costs ....................... (47,837) (10,076) Proceeds from restricted cash ................... (15,776) (191) --------- --------- Net cash used in investing activities ....... (590,328) (174,923) --------- --------- Cash flows from financing activities: Borrowings from construction financing .......... 79,210 -- Borrowings from non-recourse project financing .. 128,585 54,974 Repayments of non-recourse project financing .... (248,225) (141,085) Proceeds from issuance of Senior Notes .......... 600,000 296,000 Proceeds from equity offering ................... 204,585 -- Proceeds from issuance of common stock .......... 1,167 427 Write-off of deferred financing costs ........... 1,943 -- Financing costs ................................. (11,737) (6,620) --------- --------- Net cash provided by financing activities ... 755,528 203,696 --------- --------- Net increase in cash and cash equivalents ......... 223,755 51,846 Cash and cash equivalents, beginning of period .... 96,532 48,513 --------- --------- Cash and cash equivalents, end of period .......... $ 320,287 $ 100,359 ========= ========= Cash paid during the period for: Interest ........................................ $ 42,088 $ 36,121 Income taxes .................................... $ 1,471 $ 188
The accompanying notes are an integral part of these consolidated financial statements. 5 CALPINE CORPORATION AND SUBIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 1999 1. Organization and Operation of the Company Calpine Corporation, a Delaware corporation, and subsidiaries (collectively, the "Company") is engaged in the development, acquisition, ownership, and operation of power generation facilities and the sale of electricity and steam principally in the United States. The Company has ownership interests in and operates gas-fired cogeneration facilities, geothermal steam fields and geothermal power generation facilities in northern California, Washington, Texas and various locations on the East Coast. Each of the generation facilities produces electricity which is marketed to utilities and other third party purchasers. Thermal energy produced by the gas-fired cogeneration facilities is primarily sold to industrial users. 2. Summary of Significant Accounting Policies Basis of Interim Presentation -- The accompanying interim consolidated financial statements of the Company have been prepared by the Company, without audit by independent public accountants, pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the consolidated financial statements include the adjustments necessary to present fairly the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, should be read in conjunction with the audited consolidated financial statements of the Company included in the Company's annual report on Form 10-K for the year ended December 31, 1998. The results for interim periods are not necessarily indicative of the results for the entire year. Capitalized interest -- The Company capitalizes interest on projects during the construction period. For the six months ended June 30, 1999 and 1998, the Company capitalized $14.0 million and $3.7 million, respectively, of interest in connection with the construction of power plants. Derivative financial instruments -- The Company engages in activities to manage risks associated with changes in interest rates. The Company has entered into swap agreements to reduce exposure to interest rate fluctuations in connection with certain debt commitments. The instruments' cash flows mirror those of the underlying exposures. Unrealized gains and losses relating to the instruments are being deferred over the lives of the contracts. The premiums paid on the instruments, as measured at inception, are being amortized over their respective lives as components of interest expense. Any gains or losses realized upon the early termination of these instruments are deferred and recognized in income over the remaining life of the underlying debt. New Accounting Pronouncements -- In May 1999, the FASB issued an Exposure Draft entitled - "Deferral of the Effective Date of FASB Statement No. 133." The Exposure Draft would amend SFAS. No. 133 to defer its effective date to all fiscal quarters of all fiscal years beginning after June 15, 2000. The Company has not yet analyzed the impact of adopting SFAS No. 133 on the financial statements and has not determined the timing of or method of the adoption of SFAS No. 133. However, this Statement could increase volatility in earnings. Reclassifications -- Prior period amounts in the consolidated financial statements have been reclassified where necessary to conform to the 1999 presentation. 6 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) June 30, 1999 3. Property, Plant and Equipment Property, plant and equipment consisted of the following (in thousands): June 30, December 31, 1999 1998 ----------- ----------- Geothermal properties ........................ $ 406,893 $ 312,139 Buildings, machinery and equipment ........... 669,443 653,865 Power sales agreements ....................... 145,975 145,957 Gas contracts ................................ 122,543 122,561 Other assets ................................. 32,802 18,955 ----------- ----------- 1,377,656 1,253,477 Less accumulated depreciation and amortization (231,605) (203,984) ----------- ----------- 1,146,051 1,049,493 Land ......................................... 1,590 1,590 Construction in progress ..................... 421,241 43,220 ----------- ----------- Property, plant and equipment, net ........... $ 1,568,882 $ 1,094,303 =========== =========== Construction in progress includes costs primarily attributable to the purchase of gas-fired turbines for projects currently under development. 4. Results of Unconsolidated Investments in Power Projects The Company has unconsolidated investments in power projects which are accounted for under the equity method. Investments in less-than-majority-owned affiliates and the nature and extent of these investments change over time. The combined results of operations and financial position of the Company's equity-basis affiliates are summarized below (in thousands): Six Months Ended June 30, ------------------------ 1999 1998 ----------- ---------- Condensed Combined Statements of Operations: Revenue ...................................... $ 231,531 $ 187,216 Net income ................................... $ 48,001 $ 19,429 Company's share of net income ................ $ 18,321 $ 6,853 June 30, December 31, ------------------------ 1999 1998 ----------- ---------- Condensed Combined Balance Sheets: Assets ....................................... $1,315,950 $1,274,202 Liabilities .................................. $1,030,275 $1,000,812 The following details the Company's income from investments in unconsolidated power projects and the service contract revenue recorded by the Company related to those power projects (in thousands): Service Income Contract Revenue ------------------- ------------------- Ownership Six Months Ended June 30, Interest 1999 1998 1999 1998 ---------- -------- -------- -------- -------- Sumas Power Plant (1) .... -- $ 14,243 $ 2,872 $ 1,322 $ 809 Gordonsville Power Plant . 50% 1,872 1,785 -- -- Lockport Power Plant ..... 11.4% 1,980 1,785 -- -- Texas Cogeneration Company -- -- 2,922 -- 2,749 Bayonne Power Plant ...... 7.5% 1,912 406 -- -- Kennedy International Airport Power Plant ..... 50% (1,592) (2,686) 418 -- Sheridan Gas Fields ...... 20% 100 -- -- -- Auburndale Power Plant ... 5% (273) (590) -- -- Stony Brook Power Plant .. 50% (57) 231 468 -- Agnews Power Plant ....... 20% (54) (98) 1,010 948 Aidlin Power Plant ....... 50% 190 226 1,200 1,638 -------- -------- -------- -------- Total .......... $ 18,321 $ 6,853 $ 4,418 $ 6,144 ======== ======== ======== ======== 7 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) June 30, 1999 (1) On December 31, 1998, the Partnership agreement governing Sumas Cogeneration Company, L.P. ("Sumas") was amended changing the distributions schedule for the Company from the previously amended agreement dated September 30, 1997. The newly amended agreement reflects the earnings the Company was entitled to under that agreement from a variable payment schedule to a fixed payment schedule. On September 30, 1997, the partnership agreement was amended changing the distribution percentages to the partners. As provided for in the amendment, the Company's percentage share of the project's cash flow increased from 50% to approximately 70% through June 30, 2001, based on certain specified payments. Thereafter, the Company will receive 50% of the project's cash flow until a 24.5% pre-tax rate of return on its original investment is achieved, at which time the Company's equity interest in the partnership will be reduced to 0.1%. As a result of the amendment of the partnership agreement and the receipt of certain distributions during 1997, the Company's investment in Sumas was reduced to zero. Because the investment has been reduced to zero and there are no continuing obligations of the Company related to Sumas, the Company expects that income recorded in future periods will approximate the amount of cash received from partnership distributions. 5. Common Stock and Senior Notes Offering On March 26, 1999, the Company completed a public offering of 6,000,000 shares of its common stock at $31.00 per share. The net proceeds from this public offering were approximately $177.9 million. Additionally, in April 1999, the Company sold an additional 900,000 shares of common stock at $31.00 per share pursuant to the exercise of the underwriters' over-allotment option for net proceeds of approximately $26.7 million. On March 29, 1999, the Company completed a public offering of $250.0 million of its 7-5/8% Senior Notes Due 2006 ("Senior Notes Due 2006") and $350.0 million of its 7-3/4% Senior Notes Due 2009 ("Senior Notes Due 2009"). 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. 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 net proceeds from the sale of the common stock, the Senior Notes Due 2006, and the Senior Notes Due 2009 were used as follows: (i) $120.6 million to refinance indebtedness relating to the Gilroy Power Plant, (ii) $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, (iii) $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 County Power Plants, (iv) $25.0 million to complete the expansion of the Clear Lake Power Plant, (v) approximately $400.0 million to finance a portion of power generation facilities currently under construction and the projects currently under development, and (vi) the remaining $96.3 million will be used for general corporate purposes. Transaction costs incurred in connection with the Senior Notes offerings were recorded as a 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. 8 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) June 30, 1999 6. Acquisitions Unocal Transaction On March 19, 1999, the Company completed the acquisition of Unocal Corporation's Geysers geothermal steam fields in northern California for approximately $102.1 million. The steam fields fuel the Company"s 12 Sonoma County power plants, totaling 544 megawatts of capacity. The Company purchased these plants from Pacific Gas & Electric Company ("PG&E") on May 7, 1999. PG&E Transactions On May 7, 1999, the Company completed the acquisitions from PG&E, of 12 Sonoma County and 2 Lake County power plants located at The Geysers, California for approximately $212.8 million. The acquisitions were financed with a 24 year operating lease (see Note 10). The Company's geothermal steam fields fuel the facilities, which have a combined capacity of approximately 700 megawatts of electricity. All of the electricity generated from the facilities is sold into 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. 7. Construction Financing On January 4, 1999, the Company entered into a Credit Agreement with ING (U.S.) Capital LLC ("ING") to provide up to $265.0 million of non-recourse project financing for the construction of the Pasadena facility expansion. 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, the Company entered into a $10.0 million letter of credit facility. At June 30, 1999, there were no letters of credit outstanding under the facility. 8. Revolving Credit Facility and Line of Credit The Company maintains a credit facility of $100.0 million, which is available through a consortium of commercial lending institutions with The Bank of Nova Scotia as agent. A maximum of $50.0 million of the credit facility may be allocated to letters of credit. At June 30, 1999, the Company had no borrowings and $20.9 million of letters of credit outstanding under the credit facility. Borrowings bear interest at The Bank of Nova Scotia's base rate plus an applicable margin or at LIBOR plus an applicable margin. Interest is paid on the last day of each interest period for such loans, at least quarterly. The credit facility specifies that the Company maintain certain covenants, with which the Company was in compliance as of June 30, 1999. Commitment fees related to this line of credit are charged based on 0.375% of committed unused credit. At June 30, 1999, the Company had a loan facility with Union Bank with available borrowings totaling $1.1 million. As of June 30, 1999, the Company had no borrowings and $74,000 of letters of credit outstanding under the facility. Additionally, the Company had a $12.0 million letter of credit outstanding with The Bank of Nova Scotia to secure performance of the Clear Lake Power Plant. 9 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) June 30, 1999 9. Earnings per Share
June 30, 1999 June 30, 1998 ---------------------------- ---------------------------- Net Net (in thousands, except per share amounts) Income Shares EPS Income Shares EPS ------------------------------------------------------------------------------------------------------ Three Months: Basic earnings per common share: Income before extraordinary charge .... $ 18,710 26,923 $ 0.69 $ 11,928 20,105 $ 0.59 Extraordinary charge net of tax benefit of $793 and $207 ...................... 1,150 (0.04) 302 (0.01) -------- ------ -------- ------ Basic earnings per common share ....... $ 17,560 26,923 $ 0.65 $ 11,626 20,105 $ 0.58 ======== ====== ====== ======== ====== ====== Common shares issuable upon Exercise of stock options using Treasury stock method ............... 1,601 1,021 ------ ------ Diluted earnings per common share: Income before extraordinary charge .... $ 18,710 28,524 $ 0.66 $ 11,928 21,126 $ 0.56 Extraordinary charge net of tax benefit of $793 and $207 ..................... 1,150 (0.04) 302 (0.01) -------- ------ -------- ------ Diluted earnings per share ............ $ 17,560 28,524 $ 0.62 $ 11,626 21,126 $ 0.55 ======== ====== ====== ======== ====== ====== Six Months: Basic earnings per common share: Income before extraordinary charge .... $ 22,560 23,759 $ 0.95 $ 8,871 20,056 $ 0.44 Extraordinary charge net of tax benefit of $793 and $207 ..................... 1,150 (0.05) 302 (0.01) -------- ------ -------- ------ Basic earnings per share .............. $ 21,410 23,759 $ 0.90 $ 8,569 20,056 $ 0.43 ======== ====== ====== ======== ====== ====== Common shares issuable upon Exercise of stock options using Treasury stock method ............... 1,476 994 ------ ------ Diluted earnings per common share: Income before extraordinary charge .... $ 22,560 25,235 $ 0.89 $ 8,871 21,050 $ 0.42 Extraordinary charge net of tax benefit of $793 and $207 ..................... 1,150 (0.04) 302 (0.01) -------- ------ -------- ------ Diluted earnings per share ............ $ 21,410 25,235 $ 0.85 $ 8,569 21,050 $ 0.41 ======== ====== ====== ======== ====== ======
For the three months ended June 30, 1999, the Company recognized an extraordinary charge of $1.2 million or $0.04 per share (net of tax benefit of $793,000) representing the write off of deferred financing costs related to non-recourse project financing for the Gilroy Power Plant. The financing agreement was terminated and the outstanding balance of $120.6 million was repaid in April of 1999. For the three months ended June 30, 1998, the Company recognized an extraordinary charge of $302,000 or $0.01 per share (net of tax benefit of $207,000) as a result of the repurchase of $4.0 million of the 10-1/2% Senior Notes Due 2006. The notes were redeemed at a premium plus accrued interest to the date of repurchase. Unexercised employee stock options to purchase 15,000 and 48,000 shares of the Company's common stock during the six months ended June 30, 1999 and 1998, respectively, were not included in the computation of diluted shares outstanding because such inclusion would be anti-dilutive. 10. Commitments and Contingencies Production Royalties and Leases -- The Company is committed under several geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates and are not material. Certain properties also have net profits and overriding royalty interests ranging from approximately 1.45% to 28%, which are in addition to the land royalties. Most lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level. The Company leases its corporate offices and regional offices in San Jose, California, Boston, Massachusetts, Houston, Texas and Pleasanton, California, under noncancellable operating leases expiring 10 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) June 30, 1999 through 2002. Future minimum lease payments under these leases for the remainder of 1999 are approximately $1.0 million. Cogeneration Facilities Operating and Land Leases - The Company entered into long-term operating leases in June 1995, April 199, August 1998 and May 1999 for its Watsonville, King City, Greenleaf, Sonoma and Lake County cogeneration facilities and the land lease for the Pasadena Power Plant. Future minimum lease payments under these leases for the remainder of 1999 are approximately $31.1 million. In May 1999, the Company entered into a sale and leaseback transaction for certain plant and equipment located at The Geysers, California for a net book value of $231.8 million. Included in the transaction were the 12 Sonoma County and 2 Lake County power plants purchased from PG&E on May 7, 1999 (see Note 6), as well as the Sonoma Power Plant acquired from SMUD in 1998. Under the terms of the agreement, the Company received $18.5 million and recorded a deferred gain of $15.2 million on the balance sheet. The deferred gain is being amortized over the term of the lease through May 2022. Natural Gas Purchases -- The Company enters into short-term and long-term gas purchase contracts with third parties to supply gas to its gas-fired cogeneration projects. Capital expenditures -- At June 30, 1999, the Company is under contract with Siemens Westinghouse Power Corporation for a total of $814.9 million for the purchase of 23 turbines related to 11 development projects. Approximate payments related to these turbines is $369.1 million for 1999. Litigation On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and certain other parties, including the Company. Some of Indeck's claims relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville Energy L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s acquisition of a 50% interest in Auburndale Power Plant Partners Limited Partnership from Norweb Power Services (No. 1) Limited. Indeck claimed that Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortuously 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 April 1999, the court granted Calpine Gordonsville and Calpine Auburndale's motions to dismiss with prejudice, a decision which has been appealed by Indeck. The Company is unable to predict the outcome of these proceedings. There is currently a dispute between Texas-New Mexico Power Company ("TNP") and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear Lake Power Plant, regarding certain costs and other amounts that TNP has withheld from payments due under the power sales agreement from August 1997 until October 1998. TNP has withheld approximately $450,000 per month related to transmission charges. In October 1997, CLC filed a petition for declaratory order with the Texas Public Utilities Commission ("Texas PUC") requesting a declaration that TNP's withholding is in error, which petition is currently pending. Also, as of June 30, 1999, TNP has withheld approximately $7.7 million of standby power charges. In addition to the Texas PUC petition, CLC filed an action in Texas courts on October 2, 1997, alleging TNP's breach of the power sales agreement and is seeking refund of the standby charges. Both the Texas PUC action and the court action have been put on hold pending completion of a settlement. A final order was issued by the Texas PUC on July 15, 1999, approving the settlement documentation which includes an $8.0 million cash payment by TNP to CLC. An action was filed against Lockport Energy Associates, L.P. ("LEA") and the New York Public Service Commission ("NYPSC") in August 1997 by New York State Electricity and Gas Company ("NYSEG") in the Federal District Court for the Northern District of New York. NYSEG has requested the Court to direct NYPSC and the Federal Energy Regulatory Commission (the "FERC") to modify contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that the FERC violated the Public Utility Regulatory Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by 11 CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) June 30, 1999 failing to reform the NYSEG contract that was previously approved by the NYPSC. Although it is unable to predict the outcome of this case, in any event, the Company retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase the Company's interest in the Lockport Power Plant for $18.9 million, less equity distributions received by the Company, at any time before December 19, 2001. The Company is involved in various other claims and legal actions arising out of the normal course of business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company's financial position or results of operations, although no assurance can be given in this regard. 12 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Except for historical financial information contained herein, the matters discussed in this quarterly report may be considered forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended and subject to the safe harbor created by the Securities Litigation Reform Act of 1995. Such statements include declarations regarding our intent, belief or current expectations. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties; actual results could differ materially from those indicated by such forward-looking statements. Among the important factors that could cause actual results to differ materially from those indicated by such forward-looking statements are: (i) that the information is of a preliminary nature and may be subject to further adjustment, (ii) the possible unavailability of financing, (iii) risks related to the development, acquisition, and operation of power plants, (iv) the impact of avoided cost pricing, energy price fluctuations and gas price increases, (v) the impact of curtailment, (vi) the seasonal nature of our business, (vii) start-up risks, (viii) general operating risks, (ix) the dependence on third parties, (x) risks associated with international investments, (xi) risks associated with the power marketing business, (xii) changes in government regulation, (xiii) the availability of natural gas, (xiv) the effects of competition, (xv) the dependence on senior management, (xvi) volatility in our stock price, (xvii) fluctuations in quarterly results and seasonality, and (xviii) other risks identified from time to time in our reports and registration statements filed with the Securities and Exchange Commission. Management 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 June 30, 1999, we had interests in 37 power plants and steam fields predominantly in the United States, having an aggregate capacity of 3,627 megawatts. 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 by the end of 2000, 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 joint venture with Bechtel Enterprises, and will provide electricity to the San Francisco Bay area. 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 13 power plants, totaling 544 megawatts of capacity. We purchased these plants from PG&E on May 7, 1999 (see Note 6 to the Notes to Consolidated Financial Statements). 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. 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. 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. 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. 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 2001. On July 26, 1999,we announced plans to enter into a $1.0 billion revolving construction credit facility. The non-recourse credit facility will serve as a key component of our development program and will be utilized to finance the construction of a diversified portfolio of gas-fired power plants. The four-year credit facility will be used initially to fund the completion of the Sutter, South Point, Magic Valley, and Westbrook power plants currently under construction. The construction facility will be refinanced in the longer-term capital markets prior to its four-year maturity. 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 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, 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 information set forth under steam fields consists of the results for the Thermal 14 Power Company Steam Fields prior to the acquisition. (in thousands, except Three Months Ended Six Months Ended price per kilowatt hour) June 30, June 30, ------------------------ ----------------------- 1999 1998 1999 1998 ----------- ----------- ---------- ---------- Power Plants: Electricity revenues: Energy ............... $ 104,748 $ 70,446 $ 177,305 $ 93,735 Capacity ............. $ 61,410 $ 57,616 $ 106,155 $ 67,103 Megawatt hours produced 3,140,923 1,868,067 5,516,805 2,217,659 Average energy price per kilowatt hour ... $ 0.0334 $ 0.0377 $ 0.0321 $ 0.0423 Steam Fields: Steam Revenue: ......... $ 10,138 $ 7,346 $ 20,862 $ 17,960 Megawatt hours produced 500,954 452,571 1,192,722 981,114 Average price per kilowatt hour ....... $ 0.0202 $ 0.0162 $ 0.0175 $ 0.0183 Megawatt hours produced at the power plants increased 68% and 148% for the three and six months ended June 30, 1999 as compared with the same periods in 1998. This was primarily due to 1,795,553 and 3,626,670 megawatt hours of production at the Pittsburg, Pasadena, Clear Lake, Texas City and Bethpage Power Plants for the three and six months ended June 30, 1999 as well as the additional megawatt hours produced at the 14 geothermal power plants purchased from PG&E on May 7, 1999. Due to the consolidation of the power plants purchased from PG&E on May 7, 1999, our steam fields will no longer recognize any additional steam revenue. OTHER FINANCIAL DATA RATIOS Set forth below are certain other financial data and ratios for the periods indicated (in thousands, except ratio data): Three Months Ended Six Months Ended June 30, June 30, ------------------- ------------------- 1999 1998 1999 1998 -------- -------- -------- -------- Depreciation and amortization ...... $ 25,994 $ 19,522 $ 45,449 $ 32,104 Interest expense per indenture .... $ 28,931 $ 23,482 $ 52,034 $ 43,212 EBITDA ............................. $100,789 $ 67,557 $151,927 $ 93,374 EBITDA to interest expense ......... per indenture hours produced ...... $ 3.48x $ 2.88x $ 2.92x $ 2.16x 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 (i) to income from operations (determined in accordance with generally accepted accounting principles) or (ii) to cash flows from operating activities (determined in accordance with generally accepted accounting principles). Interest expense per indenture is defined as total interest expense plus one-third of all operating lease obligations, dividends paid in respect to preferred stock and cash contributions to any employee stock ownership plan used to pay interest on loans to purchase capital stock of the company. 15 Results of Operations Three and Six Months Ended June 30, 1999 Compared to Three and Six Months Ended June 30, 1998 Consolidated Operations. (Dollars in thousands) Three Months Ended Six Months Ended June 30, June 30, ------------------------- ----------------------- % % 1999 1998 Change 1999 1998 Change Revenue: ------- -------- ------ -------- -------- ------ Electricity and steam sales. $176,296 $135,408 30% $304,322 $178,798 70% Service contract revenue ... 6,466 3,048 112% 13,238 8,529 55% Income from unconsolidated investments in power projects .................. 7,509 3,099 142% 18,321 6,853 167% Interest on loans to power projects .................. 406 42 867% 709 2,562 -72% -------- -------- ------ -------- -------- ------ Total revenue ....... $190,677 $141,597 35% $336,590 $196,742 71% ======== ======== ====== ======== ======== ====== Revenue -- Total revenue increased 35% and 71% to $190.7 million and $336.6 million for the three months and six months ended June 30, 1999 compared to $141.6 million and $196.7 million in 1998. Electricity and steam sales revenue increased 30% to $176.3 million for the three months ended June 30, 1999 compared to $135.4 million in the same period in 1998. The increase is primarily attributable to the consolidation of our Geysers operation in Northern California during the second quarter of calendar 1999, which increased electricity revenues by $20.1 million. The Pasadena Power Plant, which became operational in July 1998, contributed $13.9 million in revenue during 1999. The acquisition of the Pittsburg Power Plant accounted for $5.2 million in additional electricity revenues in 1999. These increases were partially offset by a decrease of $11.1 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. Consequently, the price of electricity for these two power plants was significantly reduced compared to the price for the same period in 1998. For the six months ended June 30, 1999, electricity and steam revenues increased 70% to $304.3 million as compared to $178.8 million for the same period a year ago. These increases are primarily due an increase of $116.5 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 $6.5 million and $13.2 million for the three and six months ended June 30, 1999 compared to $3.0 million and $8.5 million for the same periods 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 increased 142% to $7.5 million for the three months ended June 30, 1999 compared to $3.1 million for the same period in 1998. The increase is primarily attributable to an increase of $4.1 million of equity income from our investment in Sumas , and $349,000 of equity income from our investment in the Bayonne Power Plant which was acquired in March 1998. For the six months ended June 30, 1999, income from unconsolidated investments in power projects 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 increased to $406,000 for the three months ended June 30, 1999 compared to $42,000 in 1998. The increase is attributable to dividend income received from Sheridan California Energy, Inc. For the six months ended June 30, 1999, interest income on loans to power projects 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, Inc. 16 Cost of revenue -- Cost of revenue increased to $128.7 million and $238.2 million for the three and six months ended June 30, 1999 compared to $96.8 million and $136.1 million for the same periods in 1998. The increases of $31.9 million and $102.1 million were 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 increased to $10.9 million for the three months ended June 30, 1999 compared to $5.8 million in 1998. For the six months ended June 30, 1999, general and administrative expenses increased to $21.0 million compared to $11.0 million for the same period in 1998. The increases were attributable to continued growth in personnel and associated overhead costs necessary to support the overall growth in our operations. Interest expense -- Interest expense increased 17% to $26.1 million for the three months ended June 30, 1999 from $22.3 million for the same period in 1998. The increase was primarily attributable to $11.6 million of interest associated with the issuance of senior notes in 1999, partially offset by an increase in capitalized interest of $8.5 million in connection with the construction of power plants as compared to the same period in 1998. For the six months ended June 30, 1999, interest expense 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 notes in 1999 and 1998, partially offset by an increase in capitalized interest of $10.2 million, and a decrease in interest expense of $5.2 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 three and six months ended June 30, 1999. The reductions from the statutory tax rate were 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. 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, develop and construct 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 June 30, ------------------------- 1999 1998 ----------- ----------- (in thousands) Cash flows from: Operating activities ......... $ 58,555 $ 23,073 Investing activities ......... (590,328) (174,923) Financing activities ......... 755,528 203,696 ----------- ----------- Total ................ $ 223,755 $ 51,846 =========== =========== Operating activities for 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. Investing activities for 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 Sheridan California Energy Inc., a $15.8 million increase in restricted cash, $79.3 million of capital expenditures related to the 17 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 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. Financing activities for 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, $794.7 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. 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. 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, construction financing, 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. On January 4, 1999, the Company 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 6,000,000 shares of our common stock at $31.00 per share. The net proceeds from this public offering were approximately $177.9 million. Additionally, in April 1999, we sold an additional 900,000 shares of common stock at $31.00 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 18 Due 2006, and the Senior Notes Due 2009 were used as follows: (i) $120.6 million to refinance indebtedness relating to the Gilroy Power Plant, (ii) $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, (iii) $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, (iv) $25.0 million to complete the expansion of the Clear Lake Power Plant, (v) approximately $400.0 million to finance a portion of power generation facilities currently under construction and the projects currently under development, and (vi) the remaining $96.3 million will be used for general corporate purposes. Transaction costs incurred in connection with the Senior Notes offering were recorded as a 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 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 $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 (See Note 8 to the Notes to Consolidated Financial Statements). The credit facility contains certain restrictions that limit or prohibit, among other things, our ability to incur indebtedness, make payments of certain indebtedness, pay dividends, make investments, engage in transactions with affiliates, create liens, sell assets and engage in mergers and consolidations. At 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%. Outlook Our strategy is to continue our rapid growth by capitalizing on the significant opportunities in the power industry, primarily through our active development and acquisition programs. In pursuing our proven growth strategy, we utilize our extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach uses our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations and power marketing, which we believe provide us with a competitive advantage. The key elements of our strategy are as follows: * Development and expansion of power plants. We are actively pursuing the development and expansion of highly efficient, low-cost, gas-fired power plants that replace old and inefficient generating facilities and meet the demand for new generation. Our strategy is to develop power plants in strategic geographic locations that enable us to leverage existing power generation assets and operate the power plants as integrated electric generation systems. This allows us to achieve significant operating synergies and efficiencies in fuel procurement, power marketing and operations and maintenance. We currently have seven new projects under construction, representing an additional 3,440 megawatts of capacity. Of these new projects, we are expanding our Pasadena facility by an 19 aggregate of 545 megawatts. In addition, the Tiverton, Rumford, Magic Valley, South Point, Sutter, and Westbrook power plants, which will produce an estimated 2,895 megawatts of electricity, are currently under construction. We have also announced plans to develop six additional power generation facilities, totaling an estimated 3,615 megawatts of electricity, in California, Texas, Arizona and Pennsylvania. On July 26, 1999, we announced plans to enter into a $1.0 billion revolving construction credit facility. The non-recourse credit facility will serve as a key component of our development program and will be utilized to finance the construction of a diversified portfolio of gas-fired power plants. The four-year credit facility will be used initially to fund the completion of the Sutter, South Point, Magic Valley, and Westbrook power plants currently under construction. The construction facility will be refinanced in the longer-term capital markets prior to its four-year maturity. * Acquisition of power plants. Our strategy is to acquire power generating facilities that meet our stringent acquisition criteria and provide significant potential for revenue, cash flow and earnings growth, and that provide the opportunity to enhance the operating efficiencies of the plants. We have significantly expanded and diversified our project portfolio through the acquisition of power generation facilities through the completion of 32 acquisitions to date. * Enhance the performance and efficiency of existing power projects. We continually seek to maximize the power generation potential of our operating assets and minimize our operating and maintenance expenses and fuel costs. This will become even more significant as our portfolio of power generation facilities expands to an aggregate of 50 power plants with an aggregate capacity of approximately 10,700 megawatts, after completion of our projects currently under construction and in development. We focus on operating our plants as an integrated system of power generation, which enables us to minimize costs and maximize operating efficiencies. We believe that achieving and maintaining a low-cost of production will be increasingly important to compete effectively in the power generation industry. Risk Factors We have substantial indebtedness that we may be unable to service and that restricts our activities. We have substantial debt that we incurred to finance the acquisition and development of power generation facilities. As of 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. 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 outstanding senior notes and our $100.0 million revolving credit facility, contain restrictive covenants. Among other things these restrictions limit or prohibit our ability to: * incur indebtedness, * make prepayments of indebtedness in whole or in part, * pay dividends, * make investments, 20 * engage in transactions with affiliates, * create liens, * sell assets, and * acquire facilities or other businesses. Also, if our management or ownership changes, our indentures may require us to make an offer to purchase our outstanding notes, including the senior notes. We cannot assure you that we will have the financial resources necessary to purchase such notes, and our board of directors cannot waive provisions in the indentures. We believe that our cash flow from operations, together with other available sources of funds, including borrowings under our existing borrowing arrangements, will be adequate to pay principal and interest on our debt and to enable us to comply with the terms of our debt agreements. If we are unable to comply with the terms of our debt agreements and fail to generate sufficient cash flow from operations in the future, we may be required to refinance all or a portion of our existing debt or to obtain additional financing. However, we may be unable to refinance or obtain additional financing because of our high levels of debt and the debt incurrence restrictions under our debt agreements. If cash flow is insufficient and refinancing or additional financing is unavailable, we may be forced to default on our debt obligations. In the event of a default under the terms of any of our indebtedness, the debt holders may accelerate the maturity of our obligations, which could cause defaults under our other obligations. Our ability to repay our debt depends upon the performance of our subsidiaries. Almost all of our operations are conducted through our subsidiaries and other affiliates. As a result, we depend almost entirely upon their earnings and cash flow to service our indebtedness, including our ability to pay the interest on and principal of our senior notes. The non-recourse project financing agreements of certain of our subsidiaries and other affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to us prior to the payment of other obligations, including operating expenses, debt service and reserves. Our subsidiaries and other affiliates are separate and distinct legal entities and have no obligation to pay any amounts due on our senior notes, and do not guarantee the payment of interest on or principal of these notes. The right of our senior note holders to receive any assets of any of our subsidiaries or other affiliates upon our liquidation or reorganization will be subordinated to the claims of any subsidiaries' or other affiliates' creditors (including trade creditors and holders of debt issued by our subsidiaries or affiliates). While the indentures impose limitations on our ability and the ability of our subsidiaries to incur additional indebtedness, the indentures do not limit the amount of non-recourse project financing that our subsidiaries may incur to finance new power generation facilities. We may be unable to secure additional financing in the future. Each power generation facility that we acquire or develop will require substantial capital investment. Our ability to arrange financing and the cost of the financing are dependent upon numerous factors. These factors include: * general economic and capital market conditions, * conditions in energy markets, * regulatory developments, * credit availability from banks or other lenders, * investor confidence in the industry and in us, * the continued success of our current power generation facilities, and * provisions of tax and securities laws that are conducive to raising capital. Financing for new facilities may not be available to us on acceptable terms in the future. We have financed our existing power generation facilities using a variety of leveraged financing structures, primarily consisting of non-recourse project financing and lease obligations. As of June 30, 1999, we had approximately $1.6 billion of total consolidated indebtedness, of which approximately 5% represented construction financing. Each construction financing, non-recourse project financing and lease obligation is 21 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. 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 amounts for preliminary engineering, permitting and legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable. If we were unable to complete the development of a facility, we would generally not be able to recover our investment in the project. The process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. We cannot assure you that we will be successful in the development of power generation facilities in the future. We have grown substantially in recent years as a result of acquisitions of interests in power generation facilities and steam fields. We believe that although the domestic power industry is undergoing consolidation and that significant acquisition opportunities are available, we are likely to confront significant competition for acquisition opportunities. In addition, we may be unable to continue to identify attractive acquisition opportunities at favorable prices or, to the extent that any opportunities are identified, we may be unable to complete the acquisitions. Our projects under construction may not commence operation as scheduled. The commencement of operation of a newly constructed power generation facility involves many risks, including: * start-up problems, * the breakdown or failure of equipment or processes, and * performance below expected levels of output or efficiency. New plants have no operating history and may employ recently developed and technologically complex equipment. Insurance is maintained to protect against certain risks, warranties are generally obtained for 22 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 if we fail 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. The continued operation of power generation facilities involves many risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes and performance below expected levels of output or efficiency. Although from time to time our power generation facilities have experienced equipment breakdowns or failures, these breakdowns or failures have not had a significant effect on the operation of the facilities or on our results of operations. For the six months ended June 30, 1999, our power generation facilities have operated at an average availability of approximately 87.3%. Although our facilities contain various redundancies and back-up mechanisms, a breakdown or failure may prevent the facility from performing under applicable power sales agreements. In addition, although insurance is maintained to protect against operating risks, the proceeds of insurance may not be adequate to cover lost revenues or increased expenses. As a result, we could be unable to service principal and interest payments under our financing obligations which could result in losing our interest in the power generation facility. Our geothermal energy reserves may be inadequate for our operations. The development and operation of geothermal energy resources are subject to substantial risks and uncertainties similar to those experienced in the development of oil and gas resources. The successful exploitation of a geothermal energy resource ultimately depends upon: * the heat content of the extractable fluids, * the geology of the reservoir, * the total amount of recoverable reserves, * operating expenses relating to the extraction of fluids, * price levels relating to the extraction of fluids, and * capital expenditure requirements relating primarily to the drilling of new wells. In connection with each geothermal power plant, we estimate the productivity of the geothermal resource and the expected decline in productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the electrical power capacity desired. An incorrect estimate by us or an unexpected decline in productivity could lower our results of operations. Geothermal reservoirs are highly complex. As a result, there exist numerous uncertainties in determining the extent of the reservoirs and the quantity and productivity of the steam reserves. Reservoir engineering is an inexact process of estimating underground accumulations of steam or fluids that cannot be measured in any precise way, and depends significantly on the quantity and accuracy of available data. As a result, the estimates of other reservoir specialists may differ materially from ours. Estimates of reserves are generally revised over time on the basis of the results of drilling, testing and production that occur after the original estimate was prepared. While we have extensive experience in the operation and development of geothermal energy resources and in preparing such estimates, we cannot assure you that we will be able to successfully manage the development and operation of our geothermal reservoirs or that we will accurately estimate the quantity or productivity of our steam reserves. 23 We depend on our electricity and thermal energy customers. Each of our power generation facilities currently relies on one or more power sales agreements with one or more utility or other customers for all or substantially all of such facility's revenue. In addition, the sales of electricity to two utility customers during 1998 comprised approximately 64% of our total revenue during that year. The loss of any one power sales agreement with any of these customers could have a negative effect on our results of operations. In addition, any material failure by any customer to fulfill its obligations under a power sales agreement could have a negative effect on the cash flow available to us and on our results of operations. We are subject to complex government regulation which could adversely affect our operations. Our activities are subject to complex and stringent energy, environmental and other governmental laws and regulations. The construction and operation of power generation facilities require numerous permits, approvals and certificates from appropriate federal, state and local governmental agencies, as well as compliance with environmental protection legislation and other regulations. While we believe that we have obtained the requisite approvals for our existing operations and that our business is operated in accordance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. Existing laws and regulations may be revised or new laws and regulations may become applicable to us that may have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed facilities may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain permits. If a project is unable to function as planned due to changing requirements or local opposition, it may create expensive delays or significant loss of value in a project. Our operations are potentially subject to the provisions of various energy laws and regulations, including the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1955, as amended ("PUHCA"), and state and local regulations. PUHCA provides for the extensive regulation of public utility holding companies and their subsidiaries. PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and owners of QFs certain exemptions from certain federal and state regulations, including rate and financial regulations. Under present federal law, we are not subject to regulation as a holding company under PUHCA, and will not be subject to such regulation as long as the plants in which we have an interest (1) qualify as QFs, (2) are subject to another exemption or waiver or (3) qualify as exempt wholesale generators ("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility must be not more than 50% owned by an electric utility company or electric utility holding company. In addition, a QF that is a cogeneration facility, such as the plants in which we currently have interests, must produce electricity as well as thermal energy for use in an industrial or commercial process in specified minimum proportions. The QF also must meet certain minimum energy efficiency standards. Any geothermal power facility which produces up to 80 megawatts of electricity and meets PURPA ownership requirements is considered a QF. If any of the plants in which we have an interest lose their QF status or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded QFs, we could become a public utility holding company, which could subject us to significant federal, state and local regulation, including rate regulation. If we become a holding company, which could be deemed to occur prospectively or retroactively to the date that any of our plants loses its QF status, all our other power plants could lose QF status because, under FICC regulations, a QF cannot be owned by an electric utility or electric utility holding company. In addition, a loss of QF status could, depending on the particular power purchase agreement, allow the power purchaser to cease taking and paying for electricity or to seek refunds of past amounts paid and thus could cause the loss of some or all contract revenues or otherwise impair the value of a project. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Such events could adversely affect our ability to service our indebtedness, including our senior notes. 24 Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at prices based on avoided costs of energy. We do not know whether this legislation will be passed or, if passed, what form it may take. We cannot assure that any legislation passed would not adversely impact our existing domestic projects. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry and increase access to electric utilities' transmission and distribution systems for independent power producers and electricity consumers. In particular, the state of California has restructured its electric industry by providing for a phased-in competitive power generation industry, with a power pool and an independent system operator, and for direct access to generation for all power purchasers outside the power exchange under certain circumstances. Although existing QF power sales contracts are to be honored under such restructuring, and all of our California operating projects are QFs, until the new system is fully implemented, it is impossible to predict what impact, if any, it may have on the operations of those projects. We may be unable to obtain an adequate supply of natural gas in the future. To date, our fuel acquisition strategy has included various combinations of our own gas reserves, gas prepayment contracts and short-, medium- and long-term supply contracts. In our gas supply arrangements, we attempt to match the fuel cost with the fuel component included in the facility's power sales agreements, in order to minimize a project's exposure to fuel price risk. We believe that there will be adequate supplies of natural gas available at reasonable prices for each of our facilities when current gas supply agreements expire. However, gas supplies may not be available for the full term of the facilities' power sales agreements, and gas prices may increase significantly. If gas is not available, or if gas prices increase above the fuel component of the facilities' power sales agreements, there could be a negative impact on our results of operations. Competition could adversely affect our performance. The power generation industry is characterized by intense competition. We encounter competition from utilities, industrial companies and other power producers. In recent years, there has been increasing competition in an effort to obtain power sales agreements. This competition has contributed to a reduction in electricity prices. In addition, many states have implemented or are considering regulatory initiatives designed to increase competition in the domestic power industry. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity. Our international investments may face uncertainties. We have one investment in geothermal steam fields located in Mexico and may pursue additional international investments. International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the countries in which we invest. Risks specifically related to investments in non-United States projects may include: * risks of fluctuations in currency valuation, * currency inconvertibility, * expropriation and confiscatory taxation, * increased regulation, and * approval requirements and governmental policies limiting returns to foreign investors. We depend on our senior management. Our success is largely dependent on the skills, experience and efforts of our senior management. The loss of the services of one or more members of our senior management could have a negative effect on our business and development. Seismic disturbances could damage our project. Areas where we operate and are developing many of our geothermal and gas-fired projects are subject to frequent low-level seismic disturbances. More significant seismic disturbances are possible. Our existing power generation facilities are built to withstand relatively significant levels of seismic disturbances, and we believe we maintain adequate insurance protection. However, earthquake, property damage or business interruption insurance may be inadequate to 25 cover all potential losses sustained in the event of serious seismic disturbances. Additionally, insurance may not continue to be available to us on commercially reasonable terms. Our results are subject to quarterly and seasonal fluctuations. Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including: * the timing and size of acquisitions, * the completion of development projects, and * variations in levels of production. Additionally, because we receive the majority of capacity payments under some of our power sales agreements during the months of May through October, our revenues and results of operations are, to some extent, seasonal. The price of our common stock is volatile. The market price for our common stock has been volatile in the past, and several factors could cause the price to fluctuate substantially in the future. These factors include: * announcements of developments related to our business, * fluctuations in our results of operations, * sales of substantial amounts of our securities into the marketplace, * general conditions in our industry or the worldwide economy, * an outbreak of war or hostilities, * a shortfall in revenues or earnings compared to securities analysts' expectations, * changes in analysts' recommendations or projections, and announcements of new acquisitions or development projects by us. The market price of our common stock may fluctuate significantly in the future, and these fluctuations may be unrelated to our performance. General market price declines or market volatility in the future could adversely affect the price of our common stock, and thus, the current market price may not be indicative of future market prices. Financial Market Risks From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations. We do not use derivative financial instruments for speculative or trading purposes. The following table summarizes the fair market value of our existing interest rate swap agreements as of June 30, 1999 (in thousands): Weighted Notional Average Fair Maturity Principal Interest Market Date Amount Rate 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. 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 26 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): Carrying Fair Maturity Date Amount Interest Rate 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 May 1999, the FASB issued an Exposure Draft entitled "Deferral of the Effective Date of FASB Statement No. 133." The Exposure Draft would amend SFAS. No. 133 to defer its effective date to all fiscal quarters of all fiscal years beginning after June 15, 2000. The Company has not yet analyzed the impact of adopting SFAS No. 133 on the financial statements and has not determined the timing of or method of the adoption of SFAS No. 133. However, this Statement could increase volatility in earnings. Year 2000 Compliance -- The "Year 2000 Problem" refers to the fact that some computer hardware, software and embedded systems were designed to read and store dates using only the last two digits of the year. We are coordinating our efforts to address the impact of Year 2000 on our business through a Year 2000 Project Team comprised of representatives from each business unit and our Year 2000 project office. The Year 2000 project office is charged with addressing additional Year 2000 related issues including, but not limited to, business continuation and other contingency planning. The Year 2000 Project Team meets regularly to monitor the efforts of assigned staff and contractors to identify, remediate and test our technology. The Year 2000 Project Team is focusing on four separate technology domains: * Corporate applications, which include core business systems; * Non-Information technology, which includes all operating and control systems; * End-User computing systems (that is, systems that are not, considered core business systems but may contain date calculations); and * Business partner and vendor systems. Corporate Applications - Corporate applications are those major core systems, such as customer information, human resources and general ledger, for which our Management Information Systems department has the responsibility. We utilize PeopleSoft for our major core systems. The PeopleSoft applications 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 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 27 total time expended in this area and help to ensure that the Company's 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. The Initial Assessment Phase was completed in December 1998. We plan to complete remediation of non-compliant systems by the fall of 1999. To date, all embedded systems that have been identified by Calpine 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: PHASE STATUS ESTIMATED COMPLETION DATE -------------------- ---------------- ------------------------- Inventory Complete September 1998 Initial Assessment Complete November 1998 Detail Assessment Complete May 1999 Remediation In-progress (98%) July 1999 - Sept 1999 Contingency Planning In-progress (5%) August 1999 - Nov 1999 Testing of embedded systems is complex because some of the testing must be completed during power plant scheduled maintenance outages. Most 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 Calpine 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 the Company's MIS staff. We expect to complete remediation and testing of the end-user computing systems by mid-1999. Business Partner and Vendor Systems - We have contracts with business partners and vendors who provide products and services to the Company. We are vigorously seeking to obtain Year 2000 assurances from these third parties. 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 1999. These responses outline to varying degrees the approaches vendors are undertaking to resolve Year 2000 issues within their own systems. Follow-up letters are being 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 scheduled to be 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, 1998 through June 30, 1999, $321,000 has been charged to expense. Approximately 9% of the estimated total cost has been 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 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. 28 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 the 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. The forward-looking statements discussed in this outlook section involve a number of risks and uncertainties. Other risks and uncertainties include, but are not limited to, the general economy, regulatory conditions, the changing environment of the power generation industry, pricing, the effects of legal and administrative cases and proceedings, and such other risks and uncertainties as may be detailed from time to time in our SEC reports and filings. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and certain other parties, including the Company. Some of Indeck's claims relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville Energy L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s acquisition of a 50% interest in Auburndale Power Plant Partners Limited Partnership from Norweb Power Services (No. 1) Limited. Indeck claimed that Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortuously 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 April 1999, the court granted Calpine Gordonsville and Calpine Auburndale's motions to dismiss with prejudice, a decision which has been appealed by Indeck. The Company is unable to predict the outcome of these proceedings. There is currently a dispute between Texas-New Mexico Power Company ("TNP") and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear Lake Power Plant, regarding certain costs and other amounts that TNP has withheld from payments due under the power sales agreement from August 1997 until October 1998. TNP has withheld approximately $450,000 per month related to transmission charges. In October 1997, CLC filed a petition for declaratory order with the Texas Public Utilities Commission ("Texas PUC") requesting a declaration that TNP's withholding is in error, which petition is currently pending. Also, as of June 30, 1999, TNP has withheld approximately $7.7 million of standby power charges. In addition to the Texas PUC petition, CLC filed an action in Texas courts on October 2, 1997, alleging TNP's breach of the power sales agreement and is seeking refund of the standby charges. Both the Texas PUC action and the court action have been put on hold pending completion of a settlement. A final order was issued by the Texas PUC on July 15, 1999, approving the settlement documentation which includes an $8.0 million cash payment by TNP to CLC. An action was filed against Lockport Energy Associates, L.P. ("LEA") and the New York Public Service Commission ("NYPSC") in August 1997 by New York State Electricity and Gas Company ("NYSEG") in the Federal District Court for the Northern District of New York. NYSEG has requested the Court to direct NYPSC and the Federal Energy Regulatory Commission (the "FERC") to modify contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that the FERC violated the Public Utility Regulatory Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by failing to reform the NYSEG contract that was previously approved by the NYPSC. Although it is unable to predict the outcome of this case, in any event, the Company retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase the Company's interest in the Lockport Power Plant for $18.9 million, less equity distributions received by the Company, at any time before December 19, 2001. 29 The Company is involved in various other claims and legal actions arising out of the normal course of business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company's financial position or results of operations, although no assurance can be given in this regard. ITEM 2. CHANGE IN SECURITIES None. ITEM 3. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Reference is made to Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, in the Company's Annual Report on Form 10-K for the year ended December 31, 1998 and to the subheading "Financial Market Risks" under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" on pages 35-36 of the Company's Annual Report on Form 10-K for the year ended December 31, 1998. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Our Annual Meeting of Stockholders was held on May 27, 1999 (the "Annual Meeting") in San Jose, California. At the Annual Meeting, stockholders voted on two matters: (i) the election of two Class II directors for a term of three years expiring in 2002 and (ii) the ratification of the appointment of Arthur Andersen L.L.P. as independent auditors for Calpine for the year ending December 31, 1999. The stockholders elected management's nominees as the Class II directors in an uncontested election and ratified the appointment of independent auditors by the following votes, respectively: (i) Election of Class II directors for a three year term expiring in 2002 for Peter Cartwright and Susan C. Schwab, 20,037,508 FOR and 517,047 ABSTAIN, (ii) Election of Arthur Andersen L.L.P. as independent auditors for the year ending December 31, 1999, 20,544,967 FOR, 3,060 AGAINST, and 5,528 ABSTAIN. ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Reports on Form 8-K Current report dated May 7, 1999 and filed on May 21, 1999 Item 5. Other Events -- Announcement of the Acquisition of PG&E Power Plants Item 7. Exhibits -- Press release dated May 10, 1999 (b) Exhibits The following exhibits are filed herewith unless otherwise indicated: Exhibit Number Description - ------- ------------------------------------------------------------ 3.1 --Amended and Restated Certificate of Incorporation of Calpine Corporation, a Delaware corporation.(b) 3.2 --Amended and Restated Bylaws of Calpine Corporation, a Delaware corporation.(b) 4.1 --Indenture dated as of February 17, 1994 between the Company and Shawmut Bank of 30 Connecticut, National Association, as Trustee, including form of Notes.(a) 4.2 --Indenture dated as of May 16, 1996 between the Company and Fleet National Bank, as Trustee, including form of Notes.(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.(e) 4.4 --Indenture dated as of March 31, 1998 between the Company and The Bank of New York, as Trustee, including form of Notes.(h) 4.5 --Indenture dated as of March 26, 1999 between the Company and The Bank of New York, as Trustee, including form of Notes.(I) 4.6 --Indenture dated as of April 21, 1999 between the Company and The Bank of New York, as Trustee, including form of Notes.(I) 10.1 --Purchase Agreements 10.1.1 --Purchase and Sale Agreement dated March 27, 1997 for the purchase and sale of shares of Enron/Dominion Cogen Corp. Common Stock among Enron Power Corporation and Calpine Corporation.(f) 10.1.2 --Stock Purchase and Redemption Agreement dated March 31, 1998, among Dominion Cogen, Inc. Dominion Energy, Inc. and Calpine Finance.(f) 10.1.3 --Stock Purchase Agreement dated May 1, 1998 and between Calpine Corporation and CCNG Investments, L.P.(g) 10.2 --Power Sales Agreements 10.2.1 --Amended and Restated Energy Sales Agreement, dated December 16, 1996, between Phillips Petroleum Company and Pasadena Cogeneration, L.P.(d) 10.3 --Other Agreements 10.3.1 --Calpine Corporation Stock Option Program and forms of agreements thereunder.(a) 10.3.2 --Calpine Corporation 1996 Stock Incentive Plan and forms of agreements thereunder.(b) 10.3.3 --Calpine Corporation Employee Stock Purchase Plan and forms of agreements thereunder.(b) 10.3.4 --Amended and Restated Employment Agreement between Calpine Corporation and Mr. Peter Cartwright.(b) 10.3.5 --Executive Vice President Employment Agreement between Calpine Corporation and Ms. Ann B. Curtis.(b) 10.3.6 --Executive Vice President Employment Agreement between Calpine Corporation and Mr. Lynn A. Kerby.(b) 10.3.7 --Vice President Employment Agreement between Calpine Corporation and Mr. Ron A. Walter.(b) 10.3.8 --Vice President Employment Agreement between Calpine Corporation and Mr. Robert D. Kelly.(b) 10.3.9 --First Amended and Restated Consulting Contract between Calpine Corporation and Mr. George J. Stathakis.(b) 10.4 --Form of Indemnification Agreement for directors and officers.(b) 21.1 --Subsidiaries of the Company.(c) 27.0 --Financial Data Schedule.* ___________ (a) Incorporated by reference to Registrant's Registration Statement on Form S-1 (Registration Statement No. 33-73160). 31 (b) Incorporated by reference to Registrant's Registration Statement on Form S-1 (Registration Statement No. 333-07497). (c) Incorporated by reference to Registrant's Current Report on Form 8-K dated August 29, 1996 and filed on September 13, 1996. (d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated December 31, 1996, filed on March 27, 1996. (e) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated June 30, 1997 and filed on August 14, 1997. (f) Incorporated by reference to Registrant's Current Report on Form 8-K dated March 31, 1998 and filed on April 14, 1998. (g) Incorporated by reference to Registrant's Current Report on Form 8-K dated May 26, 1998 and filed on June 9, 1998. (h) Incorporated by reference to Registrant's Registration Statement on Form S-4, filed on August 10, 1998 (Registration Statement No. 333-61047). (i) Incorporated by reference to Registrant's Form 424B filed on March 26, 1999 with the Securities and Exchange Commission. * Filed herewith. Exhibit 27 Financial Data Schedule 32 SIGNATURES Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CALPINE CORPORATION By: /s/ Ann B. Curtis Date: August 12, 1999 --------------------------------- Ann B. Curtis Executive Vice President (Chief Financial Officer) By: /s/ Charles B. Clark, Jr. Date: August 12, 1999 ---------------------------------- Charles B. Clark, Jr. Vice President and Corporate Controller (Chief Accounting Officer) 33 EX-27 2 ARTICLE 5 FDS 6/30/99 FORM 10-Q
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CALPINE CORPORATION'S CONSOLIDATED BALANCE SHEET AS OF JUNE 30, 1999 AND FROM THE CONSOLIDATED STATEMENT OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH STATEMENTS. 0000916457 CALPINE CORPORATION 1,000 U.S. DOLLAR 6-MOS DEC-31-1999 JAN-01-1999 JUN-30-1999 1 320,287 0 118,590 0 14,504 473,809 1,568,882 231,605 2,549,750 127,380 0 0 0 27 514,100 2,549,750 304,322 336,590 226,709 238,170 25,212 0 47,171 37,105 14,545 22,560 0 1,150 0 21,410 0.90 0.85
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