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 September 30, 1997
[ ] 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
20,035,705 shares outstanding on November 10, 1997
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<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q
For the Quarter Ended September 30, 1997
INDEX
PART I. FINANCIAL INFORMATION Page No.
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets
September 30, 1997 and December 31, 1996.....................3
Condensed Consolidated Statements of Operations
Three and Nine Months Ended September 30, 1997 and 1996......4
Condensed Consolidated Statements of Cash Flows
Nine Months Ended September 30, 1997 and 1996................5
Notes to Condensed Consolidated Financial Statements.........6
ITEM 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.........................14
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings..................................21
ITEM 2. Change in Securities...............................21
ITEM 3. Defaults Upon Senior Securities....................21
ITEM 4. Submission of Matters to a Vote of
Security Holders...................................21
ITEM 5. Other Information..................................21
ITEM 6. Exhibits and Reports on Form 8-K...................21
Signatures....................................................................29
Exhibit Index.................................................................30
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<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, 1997 and December 31, 1996
(in thousands)
<TABLE>
<CAPTION>
September 30, December 31,
1997 1996
---------- ----------
<S> <C> <C>
ASSETS (unaudited)
Current assets:
Cash and cash equivalents ................................ $ 198,550 $ 100,010
Accounts receivable from related parties ................. 1,931 2,826
Accounts receivable from others .......................... 50,236 39,962
Notes receivable from related parties, current portion ... 15,564 --
Collateral securities, current portion ................... 6,046 5,470
Prepaid operating lease .................................. 13,652 12,668
Other current assets ..................................... 7,684 10,251
---------- ----------
Total current assets ................................. 293,663 171,187
Property, plant and equipment, net .......................... 710,599 650,053
Investments in power projects ............................... 74,224 13,937
Collateral securities, net of current portion ............... 86,283 89,806
Notes receivable from related parties, net of current portion 134,189 18,182
Notes receivable from Coperlasa ............................. 16,353 17,961
Restricted cash ............................................. 18,195 55,219
Other assets ................................................ 34,461 13,870
---------- ----------
Total assets ......................................... $1,367,967 $1,030,215
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of non-recourse project financing ........ $ 123,095 $ 30,627
Notes payable and short-term borrowings .................. -- 6,865
Accounts payable ......................................... 19,104 18,363
Accrued payroll and related expenses ..................... 4,178 3,912
Accrued interest payable ................................. 16,254 7,332
Other accrued expenses ................................... 8,295 7,870
---------- ----------
Total current liabilities ............................ 170,926 74,969
Non-recourse project financing, net of current portion ...... 186,403 278,640
Senior Notes ................................................ 560,043 285,000
Deferred income taxes, net .................................. 139,651 100,385
Deferred lease incentive .................................... 75,844 78,521
Other liabilities ........................................... 5,549 9,573
---------- ----------
Total liabilities .................................... 1,138,416 827,088
---------- ----------
Stockholders' equity
Common stock ............................................. 20 20
Additional paid-in capital ............................... 167,329 165,412
Retained earnings ........................................ 62,202 37,695
---------- ----------
Total stockholders' equity ........................... 229,551 203,127
---------- ----------
Total liabilities and stockholders' equity ........... $1,367,967 $1,030,215
========== ==========
The accompanying notes are an integral part of these condensed
consolidated financial statements.
</TABLE>
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<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Nine Months Ended September 30, 1997 and 1996
(in thousands, except per share amounts)
(unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------- --------- --------- ---------
1997 1996 1997 1996
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Revenue:
Electricity and steam sales ..................... $ 79,441 $ 68,281 $ 175,767 $ 140,311
Service contract revenue ........................ 3,342 172 6,871 5,606
Income from unconsolidated investments in power
projects ...................................... 3,313 1,158 7,477 2,871
Interest income on loans to power projects ...... 6,809 1,286 9,765 4,103
--------- --------- --------- ---------
Total revenue ............................... 92,905 70,897 199,880 152,891
--------- --------- --------- ---------
Cost of revenue:
Plant operating expenses, depreciation, operating
lease expense and production royalties ........ 40,435 34,384 104,711 81,219
Service contract expenses ....................... 2,704 1,469 6,223 5,953
--------- --------- --------- ---------
Total cost of revenue ....................... 43,139 35,853 110,934 87,172
--------- --------- --------- ---------
Gross profit ....................................... 49,766 35,044 88,946 65,719
Project development expenses ....................... 1,764 1,044 5,711 2,454
General and administrative expenses ................ 4,618 4,903 13,202 10,777
--------- --------- --------- ---------
Income from operations ...................... 43,384 29,097 70,033 52,488
Other expense (income):
Interest expense ................................ 17,219 12,434 43,364 31,099
Other income, net ............................... (3,896) 1,149 (11,789) (1,628)
--------- --------- --------- ---------
Income before provision for income taxes .... 30,061 15,514 38,458 23,017
Provision for income taxes ......................... 10,914 4,782 13,951 7,862
--------- --------- --------- ---------
Net income .................................. $ 19,147 $ 10,732 $ 24,507 $ 15,155
========= ========= ========= =========
Primary earnings per share:
Weighted average shares outstanding ............. 21,056 14,070 20,635 12,695
========= ========= ========= =========
Primary earnings per share ...................... $ 0.91 $ 0.76 $ 1.19 $ 1.19
========= ========= ========= =========
Fully diluted earnings per share:
Weighted average shares outstanding ............. 21,086 14,303 21,023 13,227
========= ========= ========= =========
Fully diluted earnings per share ................ $ 0.91 $ 0.75 $ 1.17 $ 1.15
========= ========= ========= =========
The accompanying notes are an integral part of these condensed
consolidated financial statements.
</TABLE>
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<PAGE>
CALPlNE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 1997 and 1996
(in thousands)
(unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
----------------------
1997 1996
--------- ---------
<S> <C> <C>
Net cash provided by operating activities ................... $ 66,429 $ 25,694
--------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment ............. (89,281) (13,189)
Acquisition of Texas Cogeneration Company, net of cash ... (192,348) --
Repayment of notes receivable ............................ 21,137 --
Investment in King City, net of cash on hand ............. -- (5,408)
Investment in King City collateral securities, net ....... -- (97,901)
Investment in Gilroy, net of cash on hand ................ -- (138,073)
Advances to Coperlasa .................................... -- (14,238)
Acquisition of Calpine Gas Company ....................... (7,621) --
Investments in power projects and capitalized costs ...... (3,172) (3,504)
Maturities of collateral securities ...................... 5,350 2,900
Decrease in restricted cash .............................. 37,024 245
Other, net ............................................... 67 (152)
--------- ---------
Net cash used in investing activities .............. (228,844) (269,320)
--------- ---------
Cash flows from financing activities:
Proceeds from issuance of Senior Notes Due 2006 .......... -- 180,000
Proceeds from issuance of Senior Notes Due 2007 .......... 275,000 --
Borrowings from line of credit ........................... 14,300 59,922
Repayments of line of credit ............................. (14,300) (79,773)
Borrowings from bank ..................................... 125,000 45,000
Repayments to bank ....................................... (11,031) (46,177)
Repayments of notes payable .............................. (7,131) --
Borrowings of non-recourse project financing ............. 4,950 116,000
Repayments of non-recourse project financing ............. (118,209) (77,754)
Proceeds from issuance of preferred stock ................ -- 50,000
Proceeds from issuance of common stock ................... 1,111 82,141
Financing costs .......................................... (9,542) (8,066)
Other, net ............................................... 807 --
--------- ---------
Net cash provided by financing activities .......... 260,955 321,293
--------- ---------
Net increase in cash and cash equivalents ................... 98,540 77,667
Cash and cash equivalents, beginning of period .............. 100,010 21,810
--------- ---------
Cash and cash equivalents, end of period .................... $ 198,550 $ 99,477
========= =========
Supplementary information -- cash paid during the period for:
Interest ................................................. $ 36,314 $ 28,170
Income taxes ............................................. $ 1,185 $ 955
The accompanying notes are an integral part of these condensed
consolidated financial statements.
</TABLE>
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<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 1997
1. Organization and Operation of the Company
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") are engaged in the development, acquisition,
ownership and operation of power generation facilities and the sale of
electricity and steam in the United States and selected international markets.
The Company has interests in and operates natural gas-fired cogeneration
facilities, geothermal steam fields and geothermal power generation facilities.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying interim condensed 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
condensed 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, 1996. The results for
interim periods are not necessarily indicative of the results for the entire
year.
Earnings Per Share -- Earnings per share is calculated using the weighted
average number of common shares and common equivalent shares, unless
antidilutive, using the treasury stock method for outstanding stock options. For
1996, net income per share also gives effect to common equivalent shares from
convertible preferred shares from the original date of issuance that
automatically converted to common shares upon completion of the Company's
initial public offering in September 1996 (using the if-converted method).
In February 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 128, Earnings Per
Share, which simplifies the standards for computing earnings per share
previously found in Accounting Principles Board Opinion ("APBO") No. 15. SFAS
No. 128 replaces the presentation of primary earnings per share with a
presentation of basic earnings per share, which excludes dilution. SFAS No. 128
also requires dual presentation of basic and diluted earnings per share on the
face of the income statement for all entities with complex capital structures
and requires a reconciliation. Diluted earnings per share is computed similarly
to fully diluted earnings per share pursuant to APBO No. 15. SFAS No. 128 must
be adopted for financial statements issued for periods ending after December 15,
1997, including interim periods; earlier application is not permitted. SFAS No.
128 requires restatement of all prior-period earnings per share data presented.
For the three and nine months ended September 30, 1997, basic and diluted
earnings per share would not be materially different than the earnings per share
presented in the accompanying condensed consolidated statement of operations.
Capitalized interest -- The Company capitalizes interest on projects during the
construction period. For the three and nine months ended September 30, 1997, the
Company capitalized $1.3 million and $2.6 million, respectively, of interest in
connection with the construction of power plants. No interest was capitalized in
1996.
Derivative Financial Instruments -- The Company engages in activities to manage
risks associated with changes in interest rates. The Company has entered into
swaps 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 exposure. At September 30, 1997, the
Company had $137.2 million of interest rate swaps on non-recourse project
financing.
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<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1997
The Company, through its wholly owned subsidiary Calpine Power Services Company
("CPSC"), markets power and energy services to utilities, wholesalers, and end
users. CPSC provides these services by entering into contracts to purchase or
supply electricity at specified delivery points and specified future dates. In
some cases, CPSC utilizes option agreements to manage its exposure to market
fluctuations. At September 30, 1997 CPSC held option contracts for the purchase
and sale of up to 50 megawatts for the period from June 1, 1998 to September 30,
1998.
Reclassifications -- Prior period amounts in the consolidated condensed
financial statements have been reclassified where necessary to conform to the
1997 presentation.
3. Accounts Receivable and Notes Receivable
Accounts receivable from related parties as of September 30, 1997 and December
31, 1996 are comprised of the following (in thousands):
September 30, December 31,
1997 1996
------ ------
(unaudited)
O.L.S. Energy-Agnews, Inc. ....... $ 408 $ 687
Geothermal Energy Partners, Ltd. . 312 350
Sumas Cogeneration Company, L.P. . 444 590
Texas Cogeneration Company ("TCC") 767 --
Electrowatt Ltd. and subsidiaries -- 1,199
------ ------
$1,931 $2,826
====== ======
Notes receivable from related parties as of September 30, 1997 and December 31,
1996 are comprised of the following (in thousands):
September 30, December 31,
1997 1996
-------- --------
(unaudited)
Darrel Jones ..................... $ 10,004 $ 18,182
Cogenron, Inc. (subsidiary of TCC) 42,378 --
Clear Lake Cogeneration, L.P......
(subsidiary of TCC) ............ 97,371 --
-------- --------
$149,753 $ 18,182
======== ========
Darrel Jones is the sole shareholder of Sumas Energy, Inc., the Company's
partner in Sumas Cogeneration Company, L.P. (see Note 4). See Note 5 for
information regarding TCC.
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<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1997
4. Investments in Power Projects
The Company has unconsolidated investments in power projects which are
accounted for under the equity method. Unaudited financial information for the
nine months ended September 30, 1997 and 1996 (except Texas Cogeneration
Company, L.P., which was acquired on June 23, 1997) related to these investments
is as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996
---------------------------------------------------------- ------------------------------------------
Sumas O.L.S. Geothermal Texas Sumas O.L.S. Geothermal
Cogeneration Energy- Energy Cogeneration Cogeneration Energy- Energy
Company, Agnews, Partners, Company, Company, Agnews, Partners,
L.P. Inc. Ltd. L.P. L.P. Inc. Ltd.
-------------- --------- ------------- ------------- -------------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenue $28,839 $10,203 $18,290 $78,789 $31,740 $8,182 $16,312
Operating expenses 13,002 7,925 9,425 66,962 19,404 5,942 8,787
------- ------- ------- ------- ------- ------ ------
Income from operations 15,837 2,278 8,865 11,827 12,336 2,240 7,525
Other expenses, net 7,329 2,505 2,826 3,123 7,635 2,284 3,582
------- ------- ------ ------- ------- ------ ------
Net income (loss) $ 8,508 $ (227) $ 6,039 $ 8,704 $ 4,701 $ (44) $ 3,943
======= ======= ======= ======= ======= ====== =======
Company's share of net
income (loss) $ 5,423 $ (45) $ 272 $ 1,827 $ 2,687 $ (13) $ 197
======= ======= ======= ======= ======= ====== =======
</TABLE>
On September 30, 1997, the partnership agreement governing Sumas Cogeneration
Company, L.P. was amended changing the distribution percentages to the partners.
As provided by the terms of the amendment, the Company increased its percentage
share of the project's cash flow from 50% to approximately 70% through June 30,
2001. 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 would be reduced to 0.1%.
In connection with the amended agreement, the Company's partner in Sumas
Cogeneration Company, L.P. paid off a portion of its notes payable and all
outstanding interest on its notes payable to the Company. The Company recognized
$3.5 million of interest income which had previously been deferred. The Company
also committed to provide the partner a $12.5 million line of credit which
expires December 31, 2003.
5. Texas Cogeneration Company Transaction
On June 23, 1997, Calpine completed the acquisition of a 50% equity interest in
the Texas City cogeneration facility (the "Texas City Power Plant") and the
Clear Lake cogeneration facility (the "Clear Lake Power Plant") for a total
purchase price of $35.4 million, subject to final adjustments. The Company
acquired its 50% interest in these plants through the acquisition of 50% of the
capital stock of Enron Dominion Cogen Corp. ("EDCC") from Enron Power Corp., a
wholly owned subsidiary of Enron Corp. ("Enron"). EDCC was subsequently renamed
Texas Cogeneration Company ("TCC"). The other 50% shareholder interest in TCC is
owned by Dominion Cogen, Inc. In addition to the purchase of 50% of the stock of
TCC, Calpine, through its wholly owned subsidiary, Calpine Finance Company
("CFC"), purchased from the existing lenders the $155.6 million of outstanding
non-recourse project debt of the Texas City Power Plant (approximately $53.0
million) and the Clear Lake Power Plant (approximately $102.6 million). The
acquisition of the capital stock of TCC and the purchase of the outstanding debt
from the existing lenders were financed with approximately $125.0 million of
non-recourse debt provided by The Bank of Nova Scotia, $14.3 million of
borrowings from the revolving credit facility, and $55.8 million of equity
provided by the Company (see Notes 10 and 11 for more information regarding the
revolving line of credit and the $125.0 million of non-recourse debt).
The Company accounts for its investment in TCC under the equity method. The
Texas City and Clear Lake Power Plants are operated by the Company under a
one-year contract with automatic renewal provisions.
Texas City Power Plant -- The Texas City Power Plant is a 450 megawatt natural
gas-fired combined-cycle cogeneration facility located in Texas City, Texas. The
plant commenced commercial operation in June 1987.
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<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1997
Electricity generated by the Texas City Power Plant is sold under two separate
long-term agreements to (i) Texas Utilities Generating Company ("TUEC") under an
original 12-year power sales agreement terminating in June 1999 and (ii) Union
Carbide Company ("UCC") under an original 12-year power sales agreement
terminating in June 1999. Each power sales agreement contains provisions for
capacity and energy payments. The TUEC power sales agreement provides for a firm
capacity payment for 410 megawatts. The UCC power sales agreement provides for a
firm capacity payment for 20 megawatts.
Clear Lake Power Plant -- The Clear Lake Power Plant is a 377 megawatt natural
gas/hydrogen-fired combined-cycle cogeneration facility located in Pasadena,
Texas. The plant commenced commercial operation in December 1984.
Electricity generated by the Clear Lake Power Plant is sold under three
separate long-term agreements to (i) Texas New Mexico Power Company ("TNP")
under an original 20-year power sales agreement terminating in 2004, (ii)
Houston Light & Power Company ("HL&P") under an original 10-year power sales
agreement terminating in 2005, and (ii) Hoescht Celanese Chemical Group ("HCCG")
under an original 10-year power sales agreement terminating in 2004.
Each power sales agreement contains provisions for capacity and energy payments.
6. Auburndale and Gordonsville Transaction
On October 9, 1997, Calpine completed the acquisition of a 50% interest in both
the Auburndale cogeneration facility (the "Auburndale Power Plant") and the
Gordonsville cogeneration facility (the "Gordonsville Power Plant") for a total
purchase price of $40.2 million. The Company acquired its interest in these
plants from Norweb Power Services (No. 1) Limited and Northern Hydro Limited,
both wholly owned companies of Norweb plc. The Company financed the acquisition
of the 50% interest in the two power plants utilizing existing cash resources.
The Auburndale Power Plant is a 150 megawatt natural gas-fired combined-cycle
cogeneration facility located outside of Orlando, Florida. The Auburndale Power
Plant commenced commercial operation in July 1994 and sells 131 megawatts of
capacity and energy to Florida Power Corporation under three 20-year agreements
terminating in December 2013.
The Gordonsville Power Plant is a 240 megawatt natural gas-fired combined-cycle
cogeneration facility located near Gordonsville, Virginia. The Gordonsville
Power Plant commenced commercial operations in June 1994 and sells capacity and
energy to Virginia Power Company under two 30-year power sales agreements
terminating in 2024. In addition, the power sales agreements with Virginia Power
Company provide for fixed capacity payments.
The Gordonsville and Auburndale Power Plants are operated by Edison Mission
Operations & Maintenance Inc. ("EMOM"), an affiliate of Edison Mission Energy.
The operating agreements between EMOM and the two facilities expire in December
2013. EMOM is paid on a cost-plus basis for all direct labor plus reimbursement
of certain costs, an operating fee and an incentive based upon performance.
The Company accounts for its investment in the Auburndale Power Plant and
Gordonsville Power Plant under the equity method because control of these plants
is deemed to be shared with wholly owned subsidiaries of Edison Mission Energy.
7. Dighton and Tiverton Transaction
On October 10, 1997, Calpine executed agreements with Energy Management, Inc.
("EMI"), a New England-based power developer, to invest in two merchant power
plants which will sell 434 megawatts of electricity into the deregulated New
England Power Pool and to wholesale and retail customers. The plants, to be
located in Dighton, Massachusetts and Tiverton, Rhode Island, will be developed
by EMI and are slated for start-up in early 1999 and early 2000.
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<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1997
The Company invested $16.0 million in the 169 megawatt gas-fired,
combined-cycle Dighton power plant and will have the right to receive a
preferred payment stream at a rate of approximately 12% on its investment. This
will be accounted for as an equity investment. Construction will begin in the
fourth quarter of 1997 and EMI will operate the plant when it begins operation
in 1999.
The Company has also been granted an exclusive option to purchase an ownership
interest in and to partner with EMI on the 265 megawatt gas-fired Tiverton
project. EMI and the Company will be co-general partners for the project. EMI
will operate the facility and provide management services; the Company will
provide power marketing and fuel management services for the facility. Over the
life of the project, the Company and EMI will each receive approximately 50% of
project cash flows. The Company will initially receive 70% of project cash flows
until it has received cash equal to its initial equity investment of
approximately $40.0 million.
8. Calpine Gas Company Transaction
On January 31, 1997, the Company acquired the outstanding capital stock of
Montis Niger, Inc., a natural gas production company, and certain gas reserves
from Radnor Power, a wholly-owned subsidiary of LFC Financial Corp., for $7.1
million. In addition, the Company paid $824,000 for certain working capital
items. The Company's allocation of the purchase price is subject to final
adjustments. Montis Niger, subsequently renamed to Calpine Gas Company, owns
proven natural gas reserves and an 80-mile pipeline system which provides gas to
the Company's Greenleaf 1 and 2 Power Plants in northern California. The Company
paid $7.6 million in cash for a portion of the purchase price and working
capital items, and recorded a $600,000 liability for the remainder of the
purchase price due upon completion of certain drilling obligations.
9. Gas Energy Inc. Transaction
On August 25, 1997, Calpine entered into an agreement with The Brooklyn Union
Gas Company ("BU") to acquire 100% of the capital stock of Gas Energy Inc.
("GEI") and Gas Energy Cogeneration Inc. ("GECI") for an aggregate purchase
price of $102.5 million, subject to certain adjustments (collectively referred
to as the "GEI Transaction"). GEI and GECI are both wholly owned subsidiaries of
BU and have (i) a 50% interest in the Kennedy International Airport Power Plant,
(ii) a 50% interest in the Nissequogue Power Plant, (iii) a 45% interest in the
Grumman Power Plant, (iv) an 11.36% interest in the Lockport Power Plant and (v)
a 100% interest in three fuel management companies.
The Kennedy International Airport Power Plant is a 107 megawatt gas-fired
combined-cycle cogeneration facility located in Queens, New York. Steam and
electricity generated by the Kennedy International Airport Power Plant are sold
to John F. Kennedy International Airport under a twenty year agreement
terminating in 2015.
The Nissequogue Power Plant is a 40 megawatt gas-fired cogeneration facility
located at the State University of New York at Stony Brook ("SUNY") on Long
Island, New York. Steam and electricity generated by the Nissequogue Power Plant
are sold to SUNY under a twenty year agreement terminating in 2015, and excess
electricity is sold to Long Island Lighting Company ("LILCo").
The Grumman Power Plant is a 57 megawatt gas-fired combined cycle cogeneration
facility located in Bethpage, New York. Steam and electricity generated by the
Grumman Power Plant are sold to the Northrop Grumman Corporation under a fifteen
year agreement expiring in 2004, and excess electricity is sold to LILCo.
The Lockport Power Plant is a 184 megawatt gas-fired combined cycle
cogeneration facility located in Lockport, New York. Steam and electricity
generated by the Lockport Power Plant are sold to a General Motors Plant under a
fifteen year agreement terminating in 2007, and excess electricity is sold to
New York State Electric and Gas.
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<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1997
The Company currently expects to complete these acquisitions during the fourth
quarter of 1997, upon fulfillment of all required conditions. However, there can
be no assurance that this acquisition will be completed in the anticipated time
frame.
10. Revolving Credit Facility
At September 30, 1997, the Company had a $50.0 million credit facility
available with a consortium of commercial lending institutions which include The
Bank of Nova Scotia, International Nederlanden U.S. Capital Corporation,
Sumitomo Bank of California and Canadian Imperial Bank of Commerce. At September
30, 1997, the Company had no borrowings and $7.6 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 the London Interbank
Offered Rate ("LIBOR") plus an applicable margin. Interest is paid on the last
day of each interest period for such loans, but not less often than quarterly.
The credit agreement expires in September 1999.
11. Non-Recourse Project Financing
Note Payable to Bank -- On June 23, 1997, the Company entered into a $125.0
million non-recourse financing with The Bank of Nova Scotia, the proceeds of
which were utilized for the acquisition of the 50% interest in TCC and the
purchase from the lenders of $155.6 million of outstanding non-recourse project
debt (see Note 5). The $125.0 million non-recourse financing matures on June 22,
1998. On September 30, 1997, $114.0 million of borrowings were outstanding which
bear interest at The Bank of Nova Scotia's base rate plus an applicable margin
or at LIBOR plus an applicable margin (approximately 7.0% at September 30,
1997). The Company utilized existing swap arrangements to minimize the impact of
potential changes in interest rates on the project debt. The effective interest
rate including the effect of the existing swap arrangement was approximately
8.3% at September 30, 1997.
12. Senior Notes Due 2007
On July 8, 1997, the Company issued $200.0 million aggregate principal amount
of 8 3/4% Senior Notes Due 2007. The net proceeds of $195.0 million were used as
follows: (i) $102.7 million to repay non-recourse project financing related to
Calpine Geysers Company, (ii) $6.4 million to repay a note payable to Natomas
Energy Company related to the purchase of Thermal Power Company, (iii) $14.3
million to repay borrowings under The Bank of Nova Scotia Revolving Credit
Facility, (iv) $728,000 to repay a note payable to Santa Fe Geothermal, Inc.
which would have matured in December 1997, and (v) approximately $70.9 million
for general corporate purposes. Transaction costs incurred in connection with
the debt offering were recorded as a deferred charge and are amortized over the
ten-year life of the 8 3/4% Senior Notes Due 2007.
On September 10, 1997, the Company issued an additional $75.0 million aggregate
principal amount of 8 3/4% Senior Notes Due 2007. The net proceeds of $75.8
million were used to finance acquisitions and for general corporate purposes.
In May and June 1997, the Company executed five interest rate hedging
transactions related to debt with a notional value of $182.0 million and was
designed to eliminate interest rate risk for the period from May 1997 to July 8,
1997 when $200.0 million of the 8 3/4% Senior Notes Due 2007 were priced. These
interest rate hedging transactions were designated as a hedge of the anticipated
bond offering, and the resulting $3.0 million cost resulting from the hedges is
being amortized over the life of the bonds. The effective interest rate on the
$275.0 million aggregate principal amount after the hedging transactions and the
amortization of deferred costs is 8.9%.
The 8 3/4% Senior Notes Due 2007 will mature on July 15, 2007. The Company has
no sinking fund or mandatory redemption obligations with respect to the 8 3/4%
Senior Notes Due 2007. Interest is payable semi-annually on January 15 and July
15 of each year while the 8 3/4% Senior Notes Due 2007 are outstanding,
commencing on January 15, 1998.
- 11 -
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1997
13. Preferred Share Purchase Rights
On June 5, 1997, the Board of Directors adopted a Stockholders Right Plan to
strengthen the Board's ability to protect Calpine's stockholders. The Rights
Plan is designed to protect against abusive or coercive takeover tactics that
are not in the best interests of Calpine and its stockholders. To implement the
Rights Plan, the Board of Directors declared a dividend of one preferred share
purchase right (a "Right") for each outstanding share of Common Stock, par value
$0.001 per share, held on record as of June 18, 1997. On September 30, 1997,
there were 19,905,233 Rights outstanding. Each Right initially represents a
contingent right to purchase, under certain circumstances, one one-thousandth of
a share (a "Unit") of Series A Junior Participating Preferred Stock, par value
$0.001 per share (the "Preferred Stock"), of the Company at a price of $80.00
per Unit, subject to adjustment. The Rights become exercisable and trade
independently from Calpine's Common Stock upon the public announcement of the
acquisition by a person or group of 15% or more of the Company's Common Stock,
or ten days after commencement of a tender or exchange offer that would result
in the acquisition of 15% or more of the Company's Common Stock. Each Unit of
Preferred Stock purchased upon exercise of the Rights will be entitled to a
dividend equal to any dividend declared per share of Common Stock and will have
one vote, voting together with the Common Stock. In the event of liquidation,
each unit of Preferred Stock will be entitled to any payment made per share of
Common Stock.
If Calpine is acquired in a merger or other business combination transaction
after a person or group has acquired 15% or more of the Company's Common Stock,
each Right will entitle its holder to purchase, at the Right's exercise price, a
number of the acquiring company's common shares having a market value of twice
such exercise price. In addition, if a person or group acquires 15% or more of
Calpine's Common Stock, each Right will entitle its holder (other than the
acquiring person or group) to purchase, at the Right's exercise price, a number
of fractional shares of Calpine's Preferred Stock or shares of Common Stock
having a market value of twice such exercise price.
The Rights expire June 18, 2007 unless redeemed earlier by Calpine's Board of
Directors. The rights can be redeemed by the Board at a price of $0.01 per Right
at any time before the Rights become exercisable, and thereafter only in limited
circumstances.
14. Contingencies
CPUC Restructuring -- Electricity and steam sales agreements with PG&E are
regulated by the California Public Utilities Commission ("CPUC"). In December
1995, the CPUC proposed the transition of the electric generation market to a
competitive market beginning January 1, 1998, with all consumers participating
by 2003. Since the proposed restructure would result in widespread impact on the
market structure and require participation and oversight of the Federal Energy
Regulatory Commission ("FERC"), the CPUC sought to build a California consensus
involving the legislature, the Governor, public and municipal utilities and
customers. The consensus resulted in filings with the FERC which permit both the
CPUC and FERC to collectively proceed with implementation of the new competitive
market structure.
The proposed restructure provided for phased-in customer choice (direct
access), development of a non-discriminatory market structure, full recovery of
utility stranded costs over a five-year transition period, sanctity of existing
contracts, and continuation of existing public policy programs including funds
for enhancement of in-state renewable energy technologies during the transition
period. On September 23, 1996, state legislation was passed, AB 1890 (the
"Bill"), which codified much of the CPUC restructure decision and directed the
CPUC to proceed with implementation no later than January 1, 1998. The Bill
accelerated the transition period to a fully competitive market from five years
to four years with all consumers participating by the year 2002. The Bill
provided for an electricity rate freeze for the period of transition and
mandated through issuance of rate reduction bonds a 10% rate reduction for small
commercial and residential customers effective January 1, 1998. In May 1997, the
CPUC ruled customer phase-in was not required and all utility customers would be
able to choose their electricity supplier beginning January 1, 1998. In October
1997, the FERC conditionally approved the CPUC and investor-owned utility (IOU)
filings for going forward on January 1, 1998 with implementation of the
Independent Systems Operator (ISO) for operation of the IOU-owned statewide
transmission
- 12 -
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 1997
grid system and the Power Exchange (PX) to provide an energy price auction.
Existing investor-owned utilities will continue as regulated utility
distribution companies and provide electricity distribution services for energy
service providers. The Company believes that restructuring will not have
material effect on its existing power sales agreements and, accordingly,
believes that its existing business and results of operations will not be
materially adversely affected, although there can be no assurance in this
regard.
Litigation -- The Company is involved in various claims and legal actions
arising out of the normal course of business. Management believes that these
matters will not have a material impact on the financial position or results of
operations of the Company, although there can be no assurance in this regard.
- 13 -
<PAGE>
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 on Form 10-Q may be considered
"forward-looking" statements within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
as amended and subject to the safe harbor created by the Securities Litigation
Reform Act of 1995. Such statements include declarations regarding the intent,
belief or current expectations of the Company and its management. Prospective
investors are cautioned that any such forward-looking statements are not
guarantees of future performance and involve a number of risks and
uncertainties; actual results could differ materially from those indicated by
such forward-looking statements. Among the important factors that could cause
actual results to differ materially from those indicated by such forward-looking
statements are: (i) that the information is of a preliminary nature and may be
subject to further adjustment, (ii) 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
the Company's business, (vii) start-up risks, (viii) general operating risks,
(ix) the dependence on third parties, (x) risks associated with international
investments, (xi) risks associated with the power marketing business, (xii)
changes in government regulation, (xiii) the availability of natural gas, (xiv)
the effects of competition, (xv) the dependence on senior management, (xvi)
volatility in the Company's stock price, (xvii) fluctuations in quarterly
results and seasonality, and (xviii) other risks identified from time to time in
the Company's reports and registration statements filed with the Securities and
Exchange Commission.
OVERVIEW
Calpine is engaged in the acquisition, development, ownership and operation of
power generation facilities and the sale of electricity and steam in the United
States and selected international markets. At September 30, 1997, the Company
had interests in 16 power generation facilities and steam fields having an
aggregate capacity of 1793.5 megawatts. On October 9, 1997, the Company acquired
50% interests in two gas-fired facilities with an aggregate capacity of 390
megawatts in Virginia and Florida. In addition, Calpine has a 240 megawatt
gas-fired power generation facility under construction in Pasadena, Texas and
pending acquisitions, subject to the fulfillment of all required conditions, of
interests in four gas-fired facilities with an aggregate capacity of 388
megawatts in New York.
On January 31, 1997, the Company acquired the Calpine Gas Fields (formerly the
Montis Niger Gas Fields) for a total price of approximately $7.1 million plus
$824,000 for certain working capital items. The Calpine Gas Fields have 9.7
billion cubic feet of estimated proven gas reserves and an 80-mile pipeline
system which provide gas to the Company's Greenleaf 1 and 2 Power Plants.
In February 1997, the Company commenced construction of a 240 megawatt
gas-fired cogeneration project at the Phillips Houston Chemical Complex ("HCC")
located in Pasadena, Texas (the "Pasadena Cogeneration Project"). The Company
has entered into an agreement to supply HCC with approximately 90 megawatts,
with the remainder of available electricity output to be sold into the
competitive market. The Pasadena Cogeneration Project is the first merchant
power plant to be financed with non-recourse project debt and is scheduled to be
operational in 1998. In February 1997, the Company announced the development of
a 480 megawatt gas-fired cogeneration project in Sutter County, in northern
California (the "Sutter Cogeneration Project"). The Sutter Cogeneration Project
would be northern California's first merchant power plant. The Sutter
Cogeneration project is expected to provide electricity to the deregulated
California power market commencing in the year 2000. The Company is currently
pursuing regulatory agency permits for this project.
On May 16, 1997, the Company entered into agreements to acquire 50% interests
in the 240 megawatt Gordonsville Power Plant located west of Richmond, Virginia
and the 150 megawatt Auburndale Power Plant located outside of Orlando, Florida.
The Company completed the acquisition on October 9, 1997 for a total purchase
price of $40.2 million.
- 14 -
<PAGE>
On June 23, 1997, the Company completed the acquisition of an indirect 50%
equity interest in the 450 megawatt Texas City Power Plant and the 377 megawatt
Clear Lake Power Plant for an aggregate purchase price of $35.4 million. As a
part of that acquisition, the Company entered into a $125.0 million non-recourse
financing agreement with The Bank of Nova Scotia, the proceeds of which were
utilized for the acquisition of the 50% equity interest of TCC and the purchase
of $155.6 million of outstanding non-recourse project debt associated with the
Texas City and Clear Lake Power Plants. The Company accounts for its 50% share
of earnings from the Texas City and Clear Lake Power Plants under the equity
method of accounting and such earnings are included in "income from
unconsolidated investments in power projects".
Included in the results of operations for the three and nine months ended
September 30, 1997 are the King City and Gilroy Power Plants which each have a
generating capacity of 120 megawatts. The King City Power Plant has been
included in the Company's consolidated results of operations since the May 2,
1996 effective date of the operating lease, and the Gilroy Power Plant since its
acquisition on August 29, 1996.
Each of the Company's consolidated power plants produces electricity for sale
to a utility or, in certain instances, other third-party purchasers. Thermal
energy produced by the gas-fired cogeneration facilities is sold to governmental
and industrial users, and steam produced by the geothermal steam fields is sold
to utility-owned power plants. The electricity, thermal energy and steam
generated by these facilities are typically sold pursuant to long-term,
take-and-pay power or steam sales agreements generally having original terms of
20 or 30 years. The Company has a net interest of 421 megawatts of the aggregate
capacity generated by nine power plants that deliver electricity to Pacific Gas
and Electric Company ("PG&E") under separate long-term power sales agreements.
Each of these agreements provides for both capacity payments and energy payments
for the term of the agreement. During the initial ten-year period of certain
agreements, PG&E pays a fixed price for each unit of electrical energy according
to schedules set forth in such agreements (which represent 17%, or 73 megawatts,
of such net interest). The fixed price periods under these power sales
agreements expire at various times from 1998 through 2000. After the fixed price
periods expire, while the basis for the capacity and capacity bonus payments
under these power sales agreements remains the same, the energy payments adjust
to PG&E's then avoided cost of energy, which is determined and published each
month by the utility. The term "avoided cost" refers to the incremental costs
that an electric utility would incur to produce or purchase an amount of power
equivalent to that purchased from QFs. On December 9, 1996, the CPUC approved a
new methodology for the calculation of short-run avoided cost ("SRAC"), which
was effective retroactive to October 1, 1996 and will continue until the
independent power exchange has commenced operations and is functioning properly.
The independent power exchange is scheduled to commence operations on January 1,
1998. Thereafter, the SRAC will become the energy clearing price of the
independent power exchange. The currently prevailing SRAC is substantially lower
than the fixed energy prices under these power sales agreements and is generally
expected to remain so. While SRAC does not affect capacity payments under the
power sales agreements, in the event that the SRAC does not increase
significantly, the Company's energy revenues under these power sales agreements
would be materially reduced at the expiration of the fixed price period. Such
reduction may have a material adverse effect on the Company's results of
operations. The Company cannot predict the likely level of SRAC prices at the
expiration of the fixed price periods. The majority of the capacity revenues are
paid during the months of May through October. Prices paid for the steam
delivered by the Company's steam fields are based on a formula that partially
reflects the price levels of nuclear and fossil fuels, and therefore, a
reduction in the price levels of such fuels may reduce revenue under the steam
sales agreements for the steam fields.
Certain of the Company's power and steam sales agreements contain curtailment
provisions under which the purchasers of energy or steam are entitled to reduce
the number of hours of energy or amount of steam purchased thereunder. For the
year ended December 31, 1996, certain of the Company's power generation
facilities experienced maximum curtailment primarily as a result of low gas
prices and a high degree of precipitation during the period which resulted in
high levels of energy generation by hydroelectric power facilities that supply
electricity. For the three and nine months ended September 30, 1997, such
facilities experienced a reduced amount of curtailment compared to the same
periods in 1996. Due to an amendment to certain power sales agreements which was
executed in May 1997, the Company currently does not expect curtailment during
the remainder of the term of the power sales agreements for these power plants.
Many states are implementing or considering regulatory initiatives designed to
increase competition in the domestic power generation industry. In December
1995, the CPUC issued an electric industry restructuring decision which
envisions commencement of deregulation and implementation of customer choice of
electricity supplier by January 1,
- 15 -
<PAGE>
1998. Legislation implementing this decision was adopted in September 1996. As
part of its policy decision, the CPUC indicated that power sales agreements of
existing qualifying facilities would be honored. The Company cannot predict the
final form or timing of the proposed restructuring and the impact, if any, that
such restructuring would have on the Company's existing business or results of
operation. The Company believes that any such restructuring would not have a
material effect on its power sales agreements and, accordingly, believes that
its existing business and results of operations would not be materially
adversely affected, although there can be no assurance in this regard.
SELECTED OPERATING DATA
Set forth below is certain selected operating information for the power plants
and steam fields for which results are consolidated in the Company's statement
of operations. The information set forth under power plants consists of the
results for the West Ford Flat and Bear Canyon Power Plants, the Greenleaf 1 and
2 Power Plants, the Watsonville Power Plant, the King City Power Plant since May
2, 1996, and the Gilroy Power Plant since August 29, 1996. The information set
forth under steam fields consists of the results for the PG&E Unit 13 and Unit
16 Steam Fields, the SMUDGEO #1 Steam Fields and the Calpine Thermal Steam
Fields (dollar amounts in thousands, except per kilowatt hour amounts).
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ ------------------------
1997 1996 1997 1996
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Power Plants
Electricity revenues
Energy $ 33,180 $ 26,199 $ 77,451 $ 60,561
Capacity $ 35,105 $ 30,321 $ 67,048 $ 50,095
Megawatt hours produced 730,412 593,172 1,551,078 1,332,594
Average energy rate per
kilowatt hour produced $ 0.04543 $ 0.04417 $ 0.04993 $ 0.04545
Steam Fields
Steam revenues $ 11,155 $ 11,761 $ 31,268 $ 29,655
Megawatt hours produced 693,367 770,021 1,972,439 1,811,449
Average energy rate per
kilowatt hour produced $ 0.01609 $ 0.01527 $ 0.01585 $ 0.01637
</TABLE>
Electric energy and capacity revenue increased for the three and nine months
ended September 30, 1997 compared to the same periods in 1996, primarily due to
increases in revenue at the Gilroy, King City, West Ford Flat and Bear Canyon
Power Plants. Electricity revenues at the Gilroy Power Plant increased for the
three and nine months ended September 30, 1997 by $10.0 million and $23.4
million, respectively, as compared to the same periods in 1996. The increase was
principally due to the timing of the Company's acquisition of the power plant,
which occurred in August 1996. Higher energy prices at the King City Power Plant
contributed to an increase in energy revenue of $394,000 and $3.0 million for
the three and nine month periods ended September 30, 1997, respectively, as
compared to the same periods in 1996. Less curtailment at the West Ford Flat and
Bear Canyon Power Plants in 1997 as compared to the same periods in 1996
contributed to an increase in electric revenues of $1.0 million and $4.7 million
for the three and nine month period ended September 30, 1997, respectively. In
May 1997, the West Ford Flat and Bear Canyon Power Plants signed an agreement
with PG&E whereby energy deliveries were no longer curtailed at the two
facilities and PG&E paid a lower price for electrical energy during certain
periods. The increase in electric production more than offset the decrease in
the selling price of energy at the two facilities.
Megawatt hours produced by power plants increased in 1997 compared to the same
period in 1996, primarily due to 119,000 and 240,000 megawatt hours of increased
production by the Gilroy Power Plant for the three and nine months ended
September 30, 1997, respectively. The Gilroy Power Plant was acquired by the
Company in August 1996. During the nine months ended September 30, 1997,
Greenleaf 1 Power Plant production declined by 44,000 megawatt hours as it did
not operate for the period from January 1 to February 26, 1997 due to flooding
in the vicinity of the power plant. The average energy rate per kilowatt hour
produced for all power plants increased for the three and nine months ended
September 30, 1997 compared to the same period in 1996, primarily due to
increases in the average energy prices per kilowatt hour produced during 1997 at
certain gas-fired power plants.
- 16 -
<PAGE>
Steam field megawatt hours produced decreased for the three months ended
September 30, 1997 compared to the same periods in 1996, primarily due to lower
steam production. Increased steam usage by other facilities that share steam
fields with SMUDGEO#1 caused a decrease in the amount of steam supplied to
SMUDGEO#1 for the three months ended September 30, 1997. Megawattt hours
produced by steam fields increased for the nine months ended September 30, 1997
compared to the same period in 1996. The increase reflects the shut-down of PG&E
Unit 13 from March 23 to May 25 for installation of a new turbine rotor. In
addition, reduced output at numerous hydroelectric facilities during 1997 caused
an increase in the demand for geothermal production at the Calpine Thermal Steam
Fields. The average energy rate per kilowatt hour produced for the three months
ended September 30, 1997 was higher than the price for the comparable period in
1996, primarily due to less price discounting at Calpine Thermal Power Company.
Lower prices in accordance with power sales agreements caused the average energy
rate per kilowatt hour produced for the nine months ended September 30, 1997 to
be less than the price for the comparable period in 1996.
OTHER FINANCIAL DATA AND RATIOS
Set forth below are certain other financial data and ratios for the periods
indicated (in thousands, except ratio data):
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- ---------------------------
1997 1996 1997 1996
----------- --------- --------- ----------
<S> <C> <C> <C> <C>
Depreciation and amortization $ 13,370 $ 12,348 $ 36,919 $ 27,699
Interest expense per indenture $ 18,583 $ 13,852 $ 47,204 $ 33,933
EBITDA $ 64,702 $ 45,908 $127,398 $ 86,441
EBITDA to interest expense per indenture 3.48 3.31 2.70 2.55
</TABLE>
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 non-cash income from unconsolidated investments
in power projects. EBITDA is presented not as a measure of operating results,
but rather as a measure of the Company's ability to service debt. EBITDA should
not be construed as an alternative either (i) to income from operations
(determined in accordance with generally accepted accounting principles) or (ii)
to cash flows from operating activities (determined in accordance with generally
accepted accounting principles).
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.
RESULTS OF OPERATIONS
Three and Nine Months Ended September 30, 1997 Compared to Three and Nine
Months Ended September 30, 1996
Revenue. Total revenue was $92.9 million and $199.9 million for the three and
nine months ended September 30, 1997 compared to $70.9 million and $152.9
million for the comparable periods in 1996. Electricity and steam sales revenue
increased 16% and 25% to $79.4 million and $175.8 million for the three and nine
months ended September 30, 1997 compared to $68.3 million and $140.3 million for
the comparable periods in 1996. The increase for the three months ended
September 30, 1997 was primarily due to $10.0 million of higher revenue from the
Gilroy Power Plant acquired in August 1996. The increase for the nine months
ended September 30, 1997 was primarily due to $23.4 million of higher revenue
from the Gilroy Power Plant, $3.0 million of higher revenue from the King City
Power Plant, $6.3 million of higher revenue from the Company's geothermal power
plants, and $2.8 million due to increased prices or production at other Company
gas-fired power plants. As scheduled, the King City and Gilroy Power Plants did
not generate electrical energy and did not earn energy revenue during the four
months ended April 30, 1997. Included in geothermal revenue are revenue from the
West Ford Flat and Bear Canyon Power Plants which increased by $1.0 million and
$4.7 million for the three and nine months ended September 30, 1997 compared to
the same periods in 1996, primarily due to increased kilowatt hour generation
and increased energy prices. Thermal Power Company also contributed $263,000
- 17 -
<PAGE>
and $2.0 million more revenue for the three and nine months ended September 30,
1997 than the same periods in 1996. The increase in the three months ended
September 30, 1997 was attributed to higher energy prices, and the increase for
the nine months ended September 30, 1997 was primarily due to increased steam
sales under the alternative pricing agreement entered into with PG&E in March
1996. Service contract revenue was $3.3 million and $6.9 million for the three
and nine months ended September 30, 1997 compared to $172,000 and $5.6 million
for the comparable periods in 1996. Included within service contract revenue are
revenue from Calpine Power Services Company which recorded trading losses of
$1.9 million and $1.7 million for the three and nine months ended September 30,
1996. Income from unconsolidated investments in power projects increased to $3.3
million and $7.5 million for the three and nine months ended September 30, 1997
compared to $1.2 million and $2.9 million for the same periods in 1996. The
increase for three and nine month period ended September 30, 1997 is primarily
attributable to an increase in equity income of $685,000 and $2.7 million,
respectively, from the Company's investment in Sumas Cogeneration Company, L.P.
("Sumas"), and to equity income of $1.7 million and $1.8 million, respectively,
from the Company's June 1997 investment in Texas Cogeneration Company (see Note
5 to the Condensed Consolidated Financial Statements). In accordance with a
power sales agreement with Puget Sound Power and Light Company, Sumas operated
the plant at a minimum capacity from February to September 1997 and received a
higher price for energy sold and certain other payments. Interest income on
loans to power projects increased to $6.8 million and $9.8 million for the three
and nine months ended September 30, 1997 compared to $1.3 million and $4.1
million for the comparable periods in 1996. The increase is primarily related to
interest income on the loans to the sole shareholder of Sumas Energy, Inc., the
Company's partner in the Sumas project, and interest income on loans made by
Calpine Finance Company to the Texas City and Clear Lake Power Plants (see Note
5 to the Condensed Consolidated Financial Statements).
Cost of revenue. Cost of revenue increased 20% and 27% to $43.1 million and
$110.9 million for the three and nine months ended September 30, 1997 compared
to $35.9 million and $87.2 million for the comparable periods in 1996. The
increase was primarily due to plant operating, depreciation and operating lease
expenses attributable to the operations of the King City and Gilroy Power Plants
which have been included in the Company's operations since May 2, 1996 and
August 29, 1996, respectively.
Project development expenses increased to $1.8 million and $5.7 million for the
three and nine months ended September 30, 1997 compared to $1.0 million and $2.5
million for the same periods in 1996. The increase was due primarily to expanded
business acquisition and development activities.
General and administrative expenses. General and administrative expenses
decreased 6% to $4.6 million for the three months ended September 30, 1997
compared to $4.9 million for the same period in 1996. The decrease was primarily
due to a $1.4 million employee bonus expense related to the common stock
offering in September, 1996, partially offset by an increase in personnel and
related expenses in 1997. General and administrative expenses increased 22% to
$13.2 million for the nine months ended September 30, 1997 compared to $10.8
million for the same period in 1996. The increase in 1997 was due to additional
personnel and related expenses necessary to support the Company's expanded
operations.
Interest expense. Interest expense increased to $17.2 million and $43.4 million
for the three and nine months ended September 30, 1997 compared to $12.4 million
and $31.1 million for the comparable periods in 1996. The 39% increase for the
three months ended September 30, 1996 compared to the same period in 1996 was
attributable to $1.6 million of increased interest on debt related to the Gilroy
Power Plant acquired in August 1996, $4.6 million of increased interest on the 8
3/4% Senior Notes Due 2007 issued in July 1997, and $2.6 million increase in
interest expense at Calpine Finance Company, offset by $1.3 million of interest
capitalized for the construction of the Pasadena Power Plant and a $2.0 million
decrease in interest expense for Calpine Geysers due to repayment of the junior
and senior term loans. The 40% increase for the nine months ended September 30,
1997 compared to the same period in 1996 was attributable to $4.6 million of
increased interest expense related to the 8 3/4% Senior Notes Due 2007 issued in
July 1997, $7.3 million of increased interest expense related to the 10 1/2%
Senior Notes Due 2006 issued in May, 1996, $6.3 million of interest on debt
related to the Gilroy Power Plant acquired in August 1996 and a $2.8 million
increase of interest expense at Calpine Finance Company, offset by $2.6 million
of interest capitalized for the construction of the Pasadena Power Plant, a $2.9
million decrease in interest expense at Calpine Geysers, and a $1.8 million
decrease in interest expense at Thermal Power Company.
Other income, net. Other income, net increased to $3.9 million and $11.8
million for the three and nine months ended September 30, 1997 compared to a
loss of $1.1 million and income of $1.6 million for the same periods in 1996 due
to
- 18 -
<PAGE>
interest earned on higher cash and cash equivalent balances and interest income
earned on the collateral securities for the King City Power Plant.
Provision for income taxes. The effective income tax rate was approximately 36%
for the three and nine months ended September 30, 1997. Depletion in excess of
tax basis benefits at the Company's geothermal facilities and a revision of
prior years' tax estimates of $1.3 million and $1.7 million, respectively,
reduced the Company's effective tax rate for 1997. The effective rates for the
three and nine months ended September 30, 1996 were 31% and 34%, respectively.
In 1996, the Company decreased its deferred income tax liability by $769,000 to
reflect the change in California's state income tax rate from 9.3% to 8.84%
effective January 1, 1997. In addition, depletion in excess of tax basis
benefits at the Company's geothermal facilities reduced the Company's effective
tax rate for 1996.
LIQUIDITY AND CAPITAL RESOURCES
The following table summarizes the Company cash flow activities for the periods
indicated (in thousands):
Nine Months Ended
September 30,
-----------------------------
1997 1996
---------- ----------
Cash flows from:
Operating activities $ 66,429 $ 25,694
Investing activities (228,844) (269,320)
Financing activities 260,955 321,293
---------- ----------
Total $ 98,540 $ 77,667
========== ==========
Operating activities provided $66.4 million for the nine months ended September
30, 1997 consisting of approximately $24.5 million of net income from
operations, $11.5 million in deferred income taxes, $34.6 million of
depreciation and amortization, $9.6 million of partnership distributions and
income from unconsolidated investments in power projects and a $1.6 million
distribution from Coperlasa, offset by $15.4 million net increase in operating
assets and liabilities.
Investing activities used $228.8 million during the nine months ended September
30, 1997, primarily due to $192.3 million for the acquisition of Texas
Cogeneration Company and the related notes receivable, $66.4 million of capital
expenditures related to the construction of the Pasadena Power Plant, $22.9
million of other capital expenditures, $7.6 million for the acquisition of
Calpine Gas Company, offset by a $21.1 million of loan payments, $5.4 million of
collateral security maturities in connection with the King City Power Plant and
a $37.0 million decrease in restricted cash, primarily related to the Pasadena
Power Plant and Calpine Geysers Company, L.P.
Financing activities provided $261.0 million of cash during the nine months
ended September 30, 1997 consisting of $139.3 million of borrowings for the
acquisition of Texas Cogeneration Company and the related notes receivable, $5.0
million of borrowings for contingent consideration in connection with the
acquisition of the Gilroy Power Plant and $275.0 million of proceeds from the
issuance of the 8 3/4% Senior Notes Due 2007, offset by $118.2 million repayment
of non-recourse project debt, $25.3 million repayment of borrowings related to
the acquisition Texas Cogeneration Company, $7.1 million repayment of notes
payable and $9.5 million payment of costs associated with refinancing.
As of September 30, 1997, cash and cash equivalents were $198.6 million and
working capital was a $122.7 million. For the nine months ended September 30,
1997, cash and cash equivalents increased by $98.5 million and working capital
increased by $26.5 million as compared to the period ended December 31, 1996.
The increase in working capital is primarily due to the issuance of $275.0
million of 8 3/4% Senior Notes Due 2007, offset by the use of available cash and
proceeds from a non-recourse project financing due June 1998 in the acquisition
of Texas Cogeneration Company and in the purchase of the non-recourse project
financing of the Texas City and Clear Lake Power Plants.
As a developer, owner and operator of power generation projects, the Company may
be required to make long-term commitments and investments of substantial capital
for its projects. The Company historically has financed these capital
requirements with borrowings under its credit facilities, other lines of credit,
non-recourse project financing or long-term debt.
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<PAGE>
At September 30, 1997, the Company had outstanding $105.0 million of 9 1/4%
Senior Notes Due 2004 which mature on February 1, 2004 and bear interest payable
semi-annually on February 1 and August 1 of each year. In addition, the Company
had $180.0 million of 10 1/2% Senior Notes Due 2006 which mature on May 15, 2006
and bear interest payable semi-annually on May 15 and November 15 of each year.
Under the provisions of the applicable indentures, the Company may, under
certain circumstances, be limited in its ability to make restricted payments, as
defined, which include dividends and certain purchases and investments, incur
additional indebtedness and engage in certain transactions. On July 8, 1997, the
Company issued $200.0 million of 8 3/4% Senior Notes Due 2007 which mature on
July 15, 2007 and bear interest payable semi-annually of January 15 and July 15
of each year, beginning January 1, 1998. Of the $195.0 million of net proceeds
from the sale of the Senior Notes, the Company repaid approximately $124.1
million of existing indebtedness (see Note 12 to the Condensed Consolidated
Financial Statements for use of proceeds and further information). The Company
anticipates that a portion of the remaining net proceeds will be used to finance
potential future acquisitions. On September 10, 1997, the Company issued an
additional $75.0 million of 8 3/4% Senior Notes Due 2007. The net proceeds of
$75.8 million were used to finance acquisitions and for general corporate
purposes.
At September 30, 1997, the Company had $195.5 million of non-recourse project
financing associated with the Greenleaf 1 and 2 Power Plants and the Gilroy
Power Plant. The annual maturities for all non-recourse project financing were
$4.7 million for the remainder of 1997, $9.7 million for 1998, $8.7 million for
1999, $10.4 million for 2000, $10.6 million for 2001 and $151.5 million
thereafter.
At September 30, 1997, the Company had $114.0 million of non-recourse borrowings
from The Bank of Nova Scotia in connection with the acquisition of the notes
receivable from the Texas City and Clear Lake Power Plants. Such debt matures on
June 22, 1998.
The Company currently has a $50.0 million revolving credit agreement with a
consortium of commercial lending institutions led by The Bank of Nova Scotia,
with borrowings bearing interest at either LIBOR or at The Bank of Nova Scotia
base rate plus a mutually agreed margin. At September 30, 1997, the Company had
no borrowings outstanding and $7.6 million of letters of credit outstanding
under the revolving credit facility (see Note 10 to the Condensed Consolidated
Financial Statements). The Bank of Nova Scotia credit facility contains certain
restrictions that significantly limit or prohibit, among other things, the
ability of the Company or its subsidiaries to incur indebtedness, make payments
of certain indebtedness, pay dividends, make investments, engage in transactions
with affiliates, create liens, sell assets and engage in mergers and
consolidations.
The Company has a $1.2 million working capital line with a commercial lender
that may be used to fund short-term working capital commitments and letters of
credit. At September 30, 1997, the Company had no borrowings under this working
capital line and $74,000 of letters of credit outstanding. Borrowings bear
interest at prime plus 1%.
The Company intends to continue to seek the use of non-recourse project
financing for new projects, where appropriate. The debt agreements of the
Company's subsidiaries and other affiliates governing the non-recourse project
financing generally restrict their ability to pay dividends, make distributions
or otherwise transfer funds to the Company. The dividend restrictions in such
agreements generally require that, prior to the payment of dividends,
distributions or other transfers, the subsidiary or other affiliate must provide
for the payment of other obligations, including operating expenses, debt service
and reserves. However, the Company does not believe that such restrictions will
adversely affect its ability to meet its debt obligations.
At September 30, 1997, the Company had commitments for capital expenditures in
1997 totaling $36.8 million related to various projects at its power generation
facilities. The Company intends to fund capital expenditures for the ongoing
operation and development of the Company's power generation facilities primarily
through the operating cash flow of such facilities. Capital expenditures for the
nine months ended September 30, 1997 of $91.2 million included $66.4 million for
the construction of the Pasadena Power Plant, $9.3 million related to the
geothermal facilities, $1.4 million related to merchant power plants and the
remaining $14.1 million at the gas-fired power plants.
The Company continues to pursue the acquisition and development of new power
generation projects. The Company expects to commit significant capital in future
years for the acquisition and development of these projects. The Company's
actual capital expenditures may vary significantly during any year.
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<PAGE>
The Company believes that it will have sufficient liquidity from cash flow from
operations and borrowings available under the lines of credit and working
capital to satisfy all obligations under outstanding indebtedness, to finance
anticipated capital expenditures and to fund working capital requirements
through September 30, 1998.
Impact of Recent Accounting Pronouncements
In June 1997, the FASB issued SFAS No.130, Reporting Comprehensive Income, which
establishes standards for reporting and display of comprehensive income and its
components (revenues, expenses, gains and losses) in non- condensed
general-purpose financial statements. SFAS No.130 requires classification of
other comprehensive income by their nature in a financial statement, and the
display of the accumulated balance of other comprehensive income separately from
retained earnings and additional paid-in capital in the equity section of a
statement of financial position. SFAS No.130 is effective for fiscal years
beginning after December 15, 1997. The Company believes this pronouncement will
not have a material effect on its financial statements.
In June 1997, the FASB also issued SFAS No.131, Disclosures about Segments of an
Enterprise and Related Information, which established standards for the way
public business enterprises report information about operating segments in
annual financial statements and requires that those enterprises report selected
information about operating segments in interim financial reports to
shareholders. SFAS No.131 also establishes standards for related disclosures
about products and services, geographic areas and major customers. SFAS No.131
is effective for fiscal years beginning after December 15, 1997, although
earlier application is encouraged. The Company believes this pronouncement will
not have a material effect on its financial statements.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None.
ITEM 2. CHANGE IN SECURITIES
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
The following exhibits are filed herewith unless otherwise indicated:
Exhibit 11 Computation of Earnings Per Share
Exhibit 27 Financial Data Schedule
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<PAGE>
Exhibit
Number Description
- ------ -----------
3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation. (l)
3.2 Amended and Restated Bylaws of Calpine Corporation, a Delaware
corporation. (l)
4.1 Indenture dated as of February 17, 1994 between the Company and
Shawmut Bank of Connecticut, National Association, as Trustee,
including form of Notes. (a)
4.2 Indenture dated as of May 16, 1996 between the Company and Fleet
National Bank, as Trustee, including form of Notes. (m)
4.3 Indenture dated as of July 8, 1997, between Calpine Corporation
and The Bank of New York, as Trustee, including form of Notes. (p)
4.4 Registration Rights Agreement dated as of July 1, 1997 by and
between Calpine Corporation and Credit Suisse First Boston
Corporation, Morgan Stanley & Co. Incorporated, Salomon Brothers
Inc., Scotia Capital Markets (USA) Inc., BancAmerica Securities,
Inc. and CIBC Wood Gundy Securities Corp. (p)
10.1 Financing Agreements
10.1.1 Term and Working Capital Loan Agreement, dated as of June 1, 1990,
between Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.) and Deutsche Bank AG, New York Branch.
(a)
10.1.2 First Amendment to Term and Working Capital Loan Agreement, dated
as of June 29, 1990, between Calpine Geysers Company, L.P.
(formerly Santa Rosa Geothermal Company, L.P.) and Deutsche Bank
AG, New York Branch. (a)
10.1.3 Second Amendment to Term and Working Capital Loan Agreement, dated
as of December 1, 1990, between Calpine Geysers Company, L.P.
(formerly Santa Rosa Geothermal Company, L.P.) and Deutsche Bank
AG, New York Branch. (a)
10.1.4 Third Amendment to Term and Working Capital Loan Agreement, dated
as of June 26, 1992, between Calpine Geysers Company, L.P.
(formerly Santa Rosa Geothermal Company, L.P.), Deutsche Bank AG,
New York Branch, National Westminster Bank PLC, Union Bank of
Switzerland, New York Branch, and The Prudential Insurance Company
of America. (a)
10.1.5 Fourth Amendment to Term and Working Capital Loan Agreement, dated
as of April l, 1993, between Calpine Geysers Company, L.P.
(formerly Santa Rosa Geothermal Company, L.P.), Deutsche Bank AG,
New York Branch, National Westminster Bank PLC, Union Bank of
Switzerland, New York Branch, and The Prudential Insurance Company
of America. (a)
10.1.6 Construction and Term Loan Agreement, dated as of January 30,
1992, between Sumas Cogeneration Company, L.P., The Prudential
Insurance Company of America and Credit Suisse, New York Branch.
(a)
10.1.7 Amendment No. 1 to Construction and Term Loan Agreement, dated as
of May 24, 1993, between Sumas Cogeneration Company, L.P., The
Prudential Insurance Company of America and Credit Suisse, New
York Branch. (a)
10.1.8 Credit Agreement-Construction Loan and Term Loan Facility, dated
as of January 10, 1990, between Credit Suisse and O.L.S.
Energy-Agnews. (a)
10.1.9 Amendment No. 1 to Credit Agreement-Construction Loan and Term
Loan Facility, dated as of December 5, 1990, between Credit Suisse
and O.L.S. Energy-Agnews. (a)
- 22 -
<PAGE>
10.1.10 Participation Agreement, dated as of December 1, 1990, between
O.L.S. Energy-Agnews, Nynex Credit Company, Credit Suisse,
Meridian Trust Company of California and GATX Capital Corporation.
(a)
10.1.11 Facility Lease Agreement, dated as of December 1, 1990, between
Meridian Trust Company of California and O.L.S. Energy-Agnews. (a)
10.1.12 Project Revenues Agreement, dated as of December 1, 1990, between
O.L.S. Energy-Agnews, Meridian Trust Company of California and
Credit Suisse. (a)
10.1.13 Project Credit Agreement, dated as of September 30, 1995, between
Calpine Greenleaf Corporation, Greenleaf Unit One Associates,
Greenleaf Unit Two Associates, Inc. and The Sumitomo Bank,
Limited. (g)
10.1.14 Lease dated as of April 24, 1996 between BAF Energy A California
Limited Partnership, Lessor, and Calpine King City Cogen, LLC,
Lessee. (j)
10.1.15 Credit Agreement, dated as of August 28, 1996, among Calpine
Gilroy Cogen, L.P. and Banque Nationale de Paris. (l)
10.1.16 Credit Agreement, dated as of September 25, 1996, among Calpine
Corporation and The Bank of Nova Scotia. (m)
10.1.17 Credit Agreement, dated December 20, 1996, among Pasadena
Cogeneration L.P. and ING (U.S.) Capital Corporation and The Bank
Parties Hereto. (n)
10.1.18 Credit Agreement, dated as of June 23, 1997, among Calpine Finance
Company and Certain Commercial Lending Institutions, and The Bank
of Nova Scotia as the Agent for the Lenders. (p)
10.1.19 Purchase agreement dated as of July 1, 1997, among Calpine
Corporation and The Bank of New York as the Trustee. (p)
10.2 Purchase Agreements
10.2.1 Purchase Agreement, dated as of April 1, 1993, between Sonoma
Geothermal Partners, L.P., Healdsburg Energy Company, L.P. and
Freeport-McMoRan Resource Partners, Limited Partnership. (a)
10.2.2 Stock Purchase Agreement, dated as of June 27, 1994, between Maxus
International Energy Company, Natomas Energy Company, Calpine
Corporation and Calpine Thermal Power, Inc., and amendment thereto
dated July 28, 1994. (b)
10.2.3 Share Purchase Agreement dated March 30, 1995 between Calpine
Corporation, Calpine Greenleaf Corporation, Radnor Power Corp. and
LFC Financial Corp. (e)
10.2.4 Asset Purchase Agreement, dated as of August 28, 1996, among
Gilroy Energy Company, McCormick & Company, Incorporated and
Calpine Gilroy Cogen, L.P. (m)
10.2.5 Noncompetition / Earnings Contingency Agreement, dated as of
August 28, 1996, among Gilroy Energy Company, McCormick & Company,
Incorporated and Calpine Gilroy Cogen, L.P. (m)
10.2.6 Purchase and Sale Agreement dated as of March 27, 1997 between
Enron Power Corp. and Calpine Finance Company. (p)
10.3 Power Sales Agreements
10.3.1 Long-Term Energy and Capacity Power Purchase Agreement relating to
the Bear Canyon Facility, dated November 30, 1984, between Pacific
Gas & Electric and Calpine Geysers Company, L.P. (formerly Santa
- 23 -
<PAGE>
Rosa Geothermal Company, L.P.), Amendment dated October 17, 1985,
Second Amendment dated October 19, 1988, and related documents.
(a)
10.3.2 Long-Term Energy and Capacity Power Purchase Agreement relating to
the Bear Canyon Facility, dated November 29, 1984, between Pacific
Gas & Electric and Calpine Geysers Company, L.P. (formerly Santa
Rosa Geothermal Company, L.P.), and Modification dated November
29, 1984, Amendment dated October 17, 1985, Second Amendment dated
October 19, 1988, and related documents. (a)
10.3.3 Long-Term Energy and Capacity Power Purchase Agreement relating to
the West Ford Flat Facility, dated November 13, 1984, between
Pacific Gas & Electric and Calpine Geysers Company, L.P. (formerly
Santa Rosa Geothermal Company, L.P.), and Amendments dated May 18,
1987, June 22, 1987, July 3, 1987 and January 21, 1988, and
related documents. (a)
10.3.4 Agreement for Firm Power Purchase, dated as of February 24, 1989,
between Puget Sound Power & Light Company and Sumas Energy, Inc.
and Amendment thereto dated September 30, 1991. (a)
10.3.5 Long-Term Energy and Capacity Power Purchase Agreement, dated
April 16, 1985, between O.L.S. Energy- Agnews and Pacific Gas &
Electric Company and amendment thereto dated February 24, 1989.
(a)
10.3.6 Long-Term Energy and Capacity Power Purchase Agreement, dated
November 15, 1984, between Geothermal Energy Partners, Ltd. and
Pacific Gas & Electric Company, and related documents. (a)
10.3.7 Long-Term Energy and Capacity Power Purchase Agreement, dated
November 15, 1984, between Geothermal Energy Partners, Ltd. and
Pacific Gas & Electric Company (see Exhibit 10.3.6 for related
documents). (a)
10.3.8 Long-Term Energy and Capacity Power Purchase Agreement, dated
December 12, 1984, between Greenleaf Unit One Associates, Inc. and
Pacific Gas and Electric Company. (f)
10.3.9 Long-Term Energy and Capacity Power Purchase Agreement, dated
December 12, 1984, between Greenleaf Unit Two Associates, Inc. and
Pacific Gas and Electric Company. (f)
10.3.10 Long-Term Energy and Capacity Power Purchase Agreement, dated
December 5, 1985, between Calpine Gilroy Cogen, L.P. and Pacific
Gas and Electric Company, and Amendments thereto dated December
19, 1993, July 18, 1985, June 9, 1986, August 18, 1988 and June 9,
1991. (l)
10.3.11 Amended and Restated Energy Sales Agreement, dated December 16,
1996, between Phillips Petroleum Company and Pasadena
Cogeneration, L.P. (n)
10.4 Steam Sales Agreements
10.4.1 Geothermal Steam Sales Agreement, dated July 19, 1979, between
Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal
Company, L.P.), and Sacramento Municipal Utility District, and
related documents. (a)
10.4.2 Agreement for the Sale and Purchase of Geothermal Steam, dated
March 23, 1973, between Calpine Geysers Company, L.P. (formerly
Santa Rosa Geothermal Company, L.P.) and Pacific Gas & Electric
Company, and related letter dated May 18, 1987. (a)
10.4.3 Thermal Energy and Kiln Lease Agreement, dated as of January 16,
1992, between Sumas Cogeneration Company, L.P. and Socco, Inc.,
and Amendment thereto dated May 24, 1993. (a)
10.4.4 Amended and Restated Energy Service Agreement, dated as of
December l, 1990, between the State of California and O.L.S.
Energy-Agnews. (a)
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<PAGE>
10.4.5 Agreement for the Sale of Geothermal Steam, dated as of July 28,
1992, between Thermal Power Company and Pacific Gas & Electric
Company. (c)
10.4.6 Amendment to the Agreement for the Sale of Geothermal Steam, dated
as of August 9, 1995, between Union Oil Company of California, NEC
Acquisition Company, Thermal Power Company, and Pacific Gas and
Electric Company. (h)
10.5 Service Agreements
10.5.1 Operation and Maintenance Agreement, dated as of April 5, 1990,
between Calpine Operating Plant Services, Inc. (formerly
Calpine-Geysers Plant Services, Inc.) and Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.). (a)
10.5.2 Amended and Restated Operating and Maintenance Agreement, dated as
of January 24, 1992, between Calpine Operating Plant Services,
Inc. and Sumas Cogeneration Company, L.P. (a)
10.5.3 Amended and Restated Operation and Maintenance Agreement, dated as
of December 31, 1990, between O.L.S. Energy-Agnews and Calpine
Operating Plant Services, Inc. (formerly Calpine Cogen-Agnews,
Inc.). (a)
10.5.4 Operating and Maintenance Agreement, dated as of January 1, 1995,
between Calpine Corporation and Geothermal Energy Partners, Ltd.
(h)
10.5.5 Amended and Restated Operating Agreement for the Geysers, dated as
of December 31, 1993, by and between Magma-Thermal Power Project,
a joint venture composed of NEC Acquisition Company and Thermal
Power Company, and Union Oil Company of California. (c)
10.6 Gas Supply Agreements
10.6.1 Gas Sale and Purchase Agreement, dated as of December 23, 1991,
between ENCO Gas, Ltd. and Sumas Cogeneration Company, L.P. (a)
10.6.2 Gas Management Agreement, dated as of December 23, 1991, between
Canadian Hydrocarbons Marketing Inc., ENCO Gas, Ltd. and Sumas
Cogeneration Company, L.P. (a)
10.6.4 Natural Gas Sales Agreement, dated as of November 1, 1993, between
O.L.S. Energy-Agnews, Inc. and Amoco Energy Trading Corporation.
(a)
10.6.5 Natural Gas Service Agreement, dated November 1, 1993, between
Pacific Gas & Electric Company and O.L.S. Energy-Agnews, Inc. (a)
10.7 Agreements Regarding Real Property
10.7.1 Office Lease, dated March 15, 1991, between 50 West San Fernando
Associates, L.P. and Calpine Corporation. (a)
10.7.2 First Amendment to Office Lease, dated April 30, 1992, between 50
West San Fernando Associates, L.P. and Calpine Corporation. (a)
10.7.3 Geothermal Resources Lease CA 1862, dated July 25, 1974, between
the United States Bureau of Land Management and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.). (a)
10.7.4 Geothermal Resources Lease PRC 5206.2, dated December 14, 1976,
between the State of California and Calpine Geysers Company, L.P.
(formerly Santa Rosa Geothermal Company, L.P.). (a)
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<PAGE>
10.7.5 First Amendment to Geothermal Resources Lease PRC 5206.2, dated
April 20,1994, between the State of California and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.). (a)
10.7.6 Industrial Park Lease Agreement, dated December 18, 1990, between
Port of Bellingham and Sumas Energy, Inc. (a)
10.7.7 First Amendment to Industrial Park Lease Agreement, dated as of
July 16, 1991, between Port of Bellingham, Sumas Energy, Inc., and
Sumas Cogeneration Company, L.P. (a)
10.7.8 Second Amendment to Industrial Park Lease Agreement, dated as of
December 17, 1991, between Port of Bellingham and Sumas
Cogeneration Company, L.P. (a)
10.7.9 Amended and Restated Cogeneration Lease, dated as of December 1,
1990, between the State of California and O.L.S. Energy-Agnews.
(a)
10.8 General
10.8.1 Limited Partnership Agreement of Sumas Cogeneration Company, L.P.,
dated as of August 28, 1991, between Sumas Energy, Inc. and
Whatcom Cogeneration Partners, L.P. (a)
10.8.2 First Amendment to Limited Partnership Agreement of Sumas
Cogeneration Company, L.P., dated as of January 30, 1992, between
Whatcom Cogeneration Partners, L.P. and Sumas Energy, Inc. (a)
10.8.3 Second Amendment to Limited Partnership Agreement of Sumas
Cogeneration Company, L.P., dated as of May 24, 1993, between
Whatcom Cogeneration Partners, L.P. and Sumas Energy, Inc. (a)
10.8.4 Second Amended and Restated Shareholders' Agreement, dated as of
October 22, 1993, among GATX Capital Corporation, Calpine Agnews,
Inc., JGS-Agnews, Inc., and GATX/Calpine-Agnews, Inc. (a)
10.8.5 Amended and Restated Reimbursement Agreement, dated October 22,
1993, between GATX Capital Corporation, Calpine Agnews, Inc.,
JGS-Agnews, Inc., GATX/Calpine-Agnews, Inc., and O.L.S. Energy-
Agnews, Inc. (a)
10.8.6 Amended and Restated Limited Partnership Agreement of Geothermal
Energy Partners Ltd., L.P., dated as of May 19, 1989, between
Western Geothermal Company, L.P., Sonoma Geothermal Company, L.P.,
and Cloverdale Geothermal Partners, L.P. (a)
10.8.7 Assignment and Security Agreement, dated as of January 10, 1990,
between O.L.S. Energy-Agnews and Credit Suisse. (a)
10.8.8 Pledge Agreement, dated as of January 10, 1990, between
GATX/Calpine-Agnews, Inc., and Credit Suisse. (a)
10.8.9 Equity Support Agreement, dated as of January 10, 1990, between
Calpine Corporation and Credit Suisse. (a)
10.8.10 Assignment and Security Agreement, dated as of December 1, 1990,
between O.L.S. Energy-Agnews and Meridian Trust Company of
California. (a)
10.8.11 First Amended and Restated Limited Partner Pledge and Security
Agreement, dated as of April 1, 1993, between Sonoma Geothermal
Partners, L.P., Healdsburg Energy Company, L.P., Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.),
Freeport-McMoRan Resource Partners, L.P., and Meridian Trust
Company of California. (a)
10.9.1 Calpine Corporation Stock Option Program and forms of agreements
thereunder. (a)
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<PAGE>
10.9.2 Calpine Corporation 1996 Stock Incentive Plan and forms of
agreements thereunder. (l)
10.9.3 Calpine Corporation Employee Stock Purchase Plan and forms of
agreements thereunder. (l)
10.10.1 Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright. (l)
10.10.2 Senior Vice President Employment Agreement between Calpine
Corporation and Ms. Ann B. Curtis. (l)
10.10.3 Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Lynn A. Kerby. (l)
10.10.4 Vice President Employment Agreement between Calpine Corporation
and Mr. Ron A. Walter. (l)
10.10.5 Vice President Employment Agreement between Calpine Corporation
and Mr. Robert D. Kelly. (l)
10.10.6 Amended Consulting Contract between Calpine Corporation and Mr.
George J. Stathakis. (o)
10.11 Form of Indemnification Agreement for directors and officers. (l)
------------------------------------
(a) Incorporated by reference to Registrant's Registration Statement
on Form S-1 (Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Current Report on Form
8-K dated September 9, 1994 and filed on September 26, 1994.
(c) Incorporated by reference to Registrant's Quarterly Report on Form
10-Q dated September 30, 1994 and filed on November 14, 1994.
(d) Incorporated by reference to Registrant's Annual Report on Form
10-K dated December 31, 1994 and filed on March 29, 1995.
(e) Incorporated by reference to Registrant's Current Report on Form
8-K dated April 21, 1995 and filed on May 5, 1995.
(f) Incorporated by reference to Registrant's Quarterly Report on Form
10-Q dated September 30, 1995 and filed on May 12, 1995.
(g) Incorporated by reference to Registrant's Quarterly Report on Form
10-Q dated September 30, 1995 and filed on August 14, 1995.
(h) Incorporated by reference to Registrant's Quarterly Report on Form
10-Q dated September 30, 1995 and filed on November 14, 1995.
(i) Incorporated by reference to Registrant's Annual Report on Form
10-K dated December 31, 1995 and filed on March 29, 1996.
(j) Incorporated by reference to Registrant's Current Report on Form
8-K dated May 1, 1996 and filed on May 14, 1996.
(k) Incorporated by reference to Registrant's Quarterly Report on Form
10-Q dated September 30, 1996 and filed on May 15, 1996.
(l) Incorporated by reference to Registrant's Registration Statement
on Form S-1 (Registration Statement No. 333-07497).
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<PAGE>
(m) Incorporated by reference to Registrant's Current Report on Form
8-K dated August 29, 1996 and filed on September 13, 1996.
(n) Incorporated by reference to Registrant's Annual Report on Form
10-K dated December 31, 1996 and filed on September 30, 1997.
(o) Incorporated by reference to Registrant's Quarterly Report on Form
10-Q dated March 31, 1997 and filed on May 12, 1997.
(p) Incorporated by reference to Registrant's Quarterly Report on Form
10-Q dated June 30, 1997 and filed on August 14, 1997.
(b) REPORTS ON FORM 8-K
Current report dated June 24, 1997 and filed on July 1, 1997
Item 5. Other Events -- Proposed Rule 144A offering of $200.0
million principal amount of Senior Notes Due 2007
Current report dated July 2, 1997 and filed on July 7, 1997
Item 5. Other Events -- Pricing of Rule 144A offering of $200.0
million principal amount of 8-3/4% Senior Notes
Due 2007
- 28 -
<PAGE>
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: November 14, 1997
---------------------------
Ann B. Curtis
Senior Vice President
(Chief Financial Officer)
/s/ Gloria S. Gee Date: November 14, 1997
---------------------------
Gloria S. Gee
Corporate Controller
(Chief Accounting Officer)
- 29 -
<PAGE>
EXHIBIT INDEX
Exhibit
Number Description
- ------- -----------
11 Computation of Earnings Per Share
27 Financial Data Schedule
- 30 -
EXHIBIT 11
CALPINE CORPORATION AND SUBSIDIARIES
COMPUTATION OF EARNINGS PER SHARE
(in thousands, except per share amounts)
(unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -----------------------
1997 1996 1997 1996
--------- --------- -------- --------
<S> <C> <C> <C> <C>
Net income $ 19,147 $ 10,732 $ 24,507 $ 15,155
========= ========= ======== ========
Primary earnings per share
Weighted average number of
common shares outstanding 19,976 11,044 19,913 10,606
Conversion of preferred stock -- 2,179 -- 1,541
Common shares issuable upon
exercise of stock options using
the treasury method 1,080 847 722 548
--------- --------- -------- --------
$ 21,056 $ 14,070 $ 20,635 $ 12,695
--------- --------- -------- --------
Primary earnings per share $ 0.91 $ 0.76 $ 1.19 $ 1.19
========= ========= ======== ========
Fully diluted earnings per share
Weighted average number of
common shares outstanding 19,976 11,044 19,913 10,606
Conversion of preferred stock -- 2,179 -- 1,541
Common shares issuable upon
exercise of stock options using
the treasury method 1,110 1,080 1,110 1,080
--------- --------- -------- --------
21,086 14,303 $ 21,023 13,227
--------- --------- -------- --------
Fully diluted earnings per share $ 0.91 $ 0.75 $ 1.17 $ 1.15
========= ========= ======== ========
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CALPINE
CORPORATION'S CONDENSED CONSOLIDATED BALANCE SHEET AS OF SEPTEMBER 30, 1997
AND FROM THE CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS FOR THE NINE
MONTHS ENDED SEPTEMBER 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000916457
<NAME> Calpine Corporation
<MULTIPLIER> 1,000
<CURRENCY> U.S. Dollars
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<EXCHANGE-RATE> 1
<CASH> 198,550
<SECURITIES> 6,046
<RECEIVABLES> 52,167
<ALLOWANCES> 0
<INVENTORY> 2,775
<CURRENT-ASSETS> 293,663
<PP&E> 846,701
<DEPRECIATION> 136,102
<TOTAL-ASSETS> 1,367,967
<CURRENT-LIABILITIES> 170,926
<BONDS> 746,446
0
0
<COMMON> 20
<OTHER-SE> 229,531
<TOTAL-LIABILITY-AND-EQUITY> 1,367,967
<SALES> 175,767
<TOTAL-REVENUES> 199,980
<CGS> 104,711
<TOTAL-COSTS> 110,934
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 43,364
<INCOME-PRETAX> 38,458
<INCOME-TAX> 13,951
<INCOME-CONTINUING> 24,507
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 24,507
<EPS-PRIMARY> 1.19
<EPS-DILUTED> 1.17
</TABLE>
