UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-Q
[ X ] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the quarter ended June 30, 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 19,939,233 shares outstanding on August 12, 1997
- 1 -
CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q
For the Quarter Ended June 30, 1997
INDEX
PART I. FINANCIAL INFORMATION Page No.
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets
June 30, 1997 and December 31, 1996..........................3
Condensed Consolidated Statements of Operations
Three and Six Months Ended June 30, 1997 and 1996............4
Condensed Consolidated Statements of Cash Flows
Six Months Ended June 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.........................13
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings..................................20
ITEM 2. Change in Securities...............................20
ITEM 3. Defaults Upon Senior Securities....................20
ITEM 4. Submission of Matters to a Vote of Security
Holders............................................20
ITEM 5. Other Information..................................21
ITEM 6. Exhibits and Reports on Form 8-K...................21
Signatures....................................................................29
Exhibit Index.................................................................30
- 2 -
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30, 1997 and December 31, 1996
(in thousands)
June 30, December 31,
1997 1996
---------- ----------
ASSETS (unaudited)
Current assets:
Cash and cash equivalents ................................ $ 23,436 $ 100,010
Accounts receivable from related parties ................. 1,718 2,826
Accounts receivable from others .......................... 49,623 39,962
Notes receivable from related parties, current portion ... 15,564 --
Collateral securities, current portion ................... 6,056 5,470
Prepaid operating lease .................................. 13,652 12,668
Other current assets ..................................... 5,617 10,251
---------- ----------
Total current assets ................................. 115,666 171,187
Property, plant and equipment, net .......................... 691,444 650,053
Investments in power projects ............................... 78,451 13,937
Collateral securities, net of current portion ............... 85,453 89,806
Notes receivable from related parties, net of current portion 150,902 18,182
Notes receivable from Coperlasa ............................. 16,353 17,961
Restricted cash ............................................. 25,735 55,219
Other assets ................................................ 17,064 13,870
---------- ----------
Total assets ......................................... $1,181,068 $1,030,215
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of non-recourse project financing ........ $ 156,379 $ 30,627
Notes payable and short-term borrowings .................. 7,135 6,865
Accounts payable ......................................... 11,852 18,363
Accrued payroll and related expenses ..................... 3,393 3,912
Accrued interest payable ................................. 7,115 7,332
Other accrued expenses ................................... 6,972 7,870
---------- ----------
Total current liabilities ............................ 192,846 74,969
Long-term line of credit .................................... 14,300 --
Non-recourse project financing, net of current portion ...... 264,480 278,640
Senior Notes ................................................ 285,000 285,000
Deferred income taxes, net .................................. 129,932 100,385
Deferred lease incentive .................................... 76,737 78,521
Other liabilities ........................................... 8,265 9,573
---------- ----------
Total liabilities .................................... 971,560 827,088
---------- ----------
Stockholders' equity
Common stock ............................................. 20 20
Additional paid-in capital ............................... 166,433 165,412
Retained earnings ........................................ 43,055 37,695
Total stockholders' equity ........................... 209,508 203,127
---------- ----------
Total liabilities and stockholders' equity ........... $1,181,068 $1,030,215
========== ==========
The accompanying notes are an integral part of these condensed
consolidated financial statements.
- 3 -
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 1997 and 1996
(in thousands, except per share amounts)
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
1997 1996 1997 1996
--------- --------- --------- ---------
Revenue:
Electricity and steam sales ................ $ 62,639 $ 46,255 $ 96,326 $ 72,030
Service contract revenue ................... 1,715 2,848 3,529 5,434
Income from unconsolidated investments in
power projects ........................... 2,131 298 4,164 1,713
Interest income on loans to power projects . 1,259 920 2,956 2,817
--------- --------- --------- ---------
Total revenue .......................... 67,744 50,321 106,975 81,994
--------- --------- --------- ---------
Cost of revenue:
Plant operating expenses, depreciation,
operating lease expense and production
royalties................................ 35,537 27,363 64,276 46,835
Service contract expenses .................. 1,669 2,627 3,519 4,484
--------- --------- --------- ---------
Total cost of revenue .................. 37,206 29,990 67,795 51,319
--------- --------- --------- ---------
Gross profit .................................. 30,538 20,331 39,180 30,675
Project development expenses .................. 1,786 894 3,947 1,410
General and administrative expenses ........... 4,373 3,234 8,584 5,874
--------- --------- --------- ---------
Income from operations ................. 24,379 16,203 26,649 23,391
Other expense (income):
Interest expense ........................... 13,168 10,446 26,145 18,665
Other income, net .......................... (4,292) (2,244) (7,893) (2,777)
--------- --------- --------- ---------
Income before provision for income taxes 15,503 8,001 8,397 7,503
Provision for income taxes .................... 6,103 3,284 3,037 3,080
--------- --------- --------- ---------
Net income ............................. $ 9,400 $ 4,717 $ 5,360 $ 4,423
========= ========= ========= =========
Primary earnings per share:
Weighted average shares outstanding ........ 20,998 13,362 20,425 12,007
========= ========= ========= =========
Earnings per share ......................... $ 0.45 $ 0.35 $ 0.26 $ 0.37
========= ========= ========= =========
The accompanying notes are an integral part of these condensed
consolidated financial statements.
- 4 -
CALPlNE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 1997 and 1996
(in thousands)
(unaudited)
Six Months Ended
June 30,
----------------------
1997 1996
--------- ---------
Net cash provided by operating activities ...................................... $ 16,800 $ 5,035
--------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment ................................ (57,616) (8,061)
Acquisition of Texas Cogeneration Company ................................... (36,411) --
Purchase of loans for Texas City and Clear Lake Power Plants ................ (155,622) --
Repayment of loans by Texas City and Clear Lake Power Plants ................ 5,737 --
Investment in King City, net of cash on hand ................................ -- (4,877)
Investment in King City collateral securities ............................... -- (98,414)
Acquisition of Calpine Gas Company .......................................... (7,621) --
Investments in power projects and capitalized costs ......................... (416) (2,983)
Loans to Coperlasa .......................................................... -- (12,104)
Maturities of collateral securities ......................................... 5,350 --
Decrease in restricted cash ................................................. 29,484 1,150
Other, net .................................................................. (3,382) (762)
--------- ---------
Net cash used in investing activities ................................. (220,497) (126,051)
--------- ---------
Cash flows from financing activities:
Proceeds from issuance of Senior Notes Due 2006 ............................. -- 180,000
Borrowings from line of credit .............................................. 14,300 33,800
Repayments of line of credit ................................................ -- (53,651)
Borrowings from bank ........................................................ -- 45,000
Repayments to bank .......................................................... -- (46,177)
Borrowings of non-recourse project financing ................................ 128,300 --
Repayments of non-recourse project financing ................................ (16,247) (66,600)
Proceeds from issuance of preferred stock ................................... -- 50,000
Proceeds from issuance of common stock ...................................... 954 --
Financing costs ............................................................. (251) (4,763)
Other, net .................................................................. 67 --
--------- ---------
Net cash provided by financing activities ............................. 127,123 137,609
--------- ---------
Net increase (decrease) in cash and cash equivalents ........................... (76,574) 16,593
Cash and cash equivalents, beginning of period ................................. 100,010 21,810
--------- ---------
Cash and cash equivalents, end of period ....................................... $ 23,436 $ 38,403
========= =========
Supplementary information -- cash paid during the period for:
Interest .................................................................... $ 27,039 $ 16,517
Income taxes ................................................................ $ 435 955
The accompanying notes are an integral part of these condensed
consolidated financial statements.
- 5 -
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 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 all and only normal
recurring 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 six months ended June 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 six months ended June 30, 1997, the
Company capitalized $723,000 and $1.3 million, respectively, of interest in
connection with the construction of the Pasadena Power Plant. 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.
- 6 -
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1997
At June 30, 1997, the Company had $151.7 million of interest rate swaps on
non-recourse project financing and $182.0 million of treasury rate locks and
enhanced forwards on senior notes issued by the Company in July 1997. During
July 1997, the Company extinguished non-recourse project financing related to
$64.2 million of interest rate hedges and terminated one swap related to $9.2
million of hedged debt.
Reclassifications -- Prior year 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 June 30, 1997 and December 31,
1996 are comprised of the following (in thousands):
June 30, December 31,
1997 1996
------ ------
(unaudited)
O.L.S. Energy-Agnews, Inc. ....... $ 833 $ 687
Geothermal Energy Partners, Ltd. . 191 350
Sumas Cogeneration Company, L.P. . 351 590
Texas Cogeneration Company ("TCC") 29 --
Electrowatt Ltd. and subsidiaries 314 1,199
------ ------
$1,718 $2,826
====== ======
Notes receivable from related parties as of June 30, 1997 and December 31, 1996
are comprised of the following (in thousands):
June 30, December 31,
1997 1996
--------- --------
(unaudited)
Darrel Jones ..................... $ 18,781 $ 18,182
Cogenron, Inc. (subsidiary of TCC) 47,688 --
Clear Lake Cogeneration, L.P. .....
(subsidiary of TCC) ............ 99,997 --
--------- --------
$166,466 $ 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.
- 7 -
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 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
six months ended June 30, 1997 and 1996 related to these investments is as
follows (in thousands):
1997 1996
---------------------------------------------------------- ------------------------------------------
Sumas O.L.S. Geothermal Sumas O.L.S. Geothermal
Cogeneration Energy- Energy Texas Cogeneration Energy- Energy
Company, Agnews, Partners, Cogeneration Company, Agnews, Partners,
L.P. Inc. Ltd. Company L.P. Inc. Ltd.
-------------- --------- ------------- ------------- -------------- ---------- -------------
Revenue .............. $19,354 $ 6,020 $11,584 $ 5,786 $21,561 $ 4,604 $ 9,576
Operating expenses ... 7,325 5,654 4,982 4,855 12,752 4,349 6,219
------- ------- ------- ------- ------- ------- -------
Income (loss) from
operations ......... 12,029 366 6,602 931 8,809 255 3,357
Other expenses, net .. 5,167 1,170 1,784 236 5,098 1,040 2,444
------- ------- ------- ------- ------- ------- -------
Net income (loss) $ 6,862 $ (804) $ 4,818 $ 695 $ 3,711 $ (785) $ 913
======= ======= ======= ======= ======= ======= =======
Company's share of net
income (loss) ...... $ 3,906 $ (124) $ 224 $ 158 $ 1,855 $ (179) $ 37
======= ======= ======= ======= ======= ======= =======
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 line of credit, and $55.8 million of equity
provided by the Company (see Notes 7 and 8 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 because
control of TCC is deemed to be shared with Dominion Cogen, Inc. 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
Texas City Power Plant commenced commercial operation in June 1987.
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. 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.
- 8 -
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1997
Natural gas requirements for the Texas City Power Plant are allocated between
UCC, DEI Texas, Inc. ("DEI"), an affiliate of Dominion Cogen Inc., and Enron
Capital and Trading Corporation ("ECT") pursuant to a contractual arrangement.
UCC and DEI currently provide approximately 25% and 56%, respectively, of the
fuel requirements of the Texas City Power Plant. The three fuel contracts are
effective through June 1999. Under the fuel contracts, approximately 19% of the
total fuel requirements of the Texas City Power Plant is supplied at spot market
prices. The remainder is purchased at fixed rates which are currently above spot
market prices.
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 Clear Lake Power 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.
The TNP power sales agreement provides for a firm capacity payment of
production between 200 and 250 megawatts based on 98% of HL&P's tariff under its
TNP contract. The HL&P power sales agreement provides for firm capacity payment
for 50 megawatts for the term of the agreement, subject to adjustment under
certain specified conditions. The HCCG power sales agreement provides for firm
capacity payment for 35 megawatts for the term of the agreement. The TNP energy
price is based on 98% of HL&P's tariff under its TNP contract. HL&P's and HCCG's
energy payments are based on HL&P's weighted average cost of gas, or contractual
heat rates and operations and maintenance adder.
The natural gas for the Clear Lake Power Plant is purchased primarily from TCC,
which receives its fuel from ECT on a tiered price basis consisting of a fixed
priced tier escalating at 5% annually and two index-priced tiers. A small
portion of the natural gas requirements is purchased from ECT at index prices.
In addition, the facility burns hydrogen provided by HCCG, amounting to
approximately 5% of the Clear Lake Power Plant's total fuel requirements.
6. 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.
7. Revolving Credit Facility
At June 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 June 30, 1997, the
Company had $14.3 million of borrowings and $2.7 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")
- 9 -
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1997
plus an applicable margin (approximately 9.4% at June 30, 1997). 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.
On July 1, 1997, the Company had an additional $6.0 million of letters of
credit outstanding related to the purchase of firm capacity and energy between
HL&P and the Clear Lake Power Plant. On July 8, 1997, the Company repaid the
$14.3 million of borrowings with proceeds from the 8-3/4% Senior Notes Due 2007
(see Note 9).
8. 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 and is expected to be repaid prior to maturity with the proceeds of a
planned refinancing of the $155.6 million non-recourse project debt. On June 30,
1997, $119.3 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 June 30, 1997). In July 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 8.4%.
Senior-Term and Junior Term Loans -- The Company entered into the Senior-Term
and Junior Term Loans in connection with the Company's acquisition of Calpine
Geysers Company in 1993. On June 30, 1997, $102.7 million of such loans were
outstanding. On July 8, 1997, the Company repaid all Senior-Term and Junior-Term
Loans before their maturity date from the proceeds of the 8-3/4% Senior Notes
Due 2007 (see Note 9). In connection with this transaction, the Company
terminated one swap transaction and retained one swap transaction. The Company
had entered into these swap transactions to minimize the impact of changes in
interest rates on a portion of the Senior- Term loans and had an effective rate
of 9.9% on June 30, 1997.
9. 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 which matures in
September 1997, (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 matures 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 using the effective
interest rate method.
In May and June 1997, the Company executed five interest rate hedging
transactions related to debt with a notational value of $182.0 million and
designed to eliminate interest rate risk for the period from May 1997 to July 8,
1997 when 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
amortized over the life of the bond. The effective interest rate after the
hedging transactions and the amortization of deferred costs is 9.0%.
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.
- 10 -
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1997
10. 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 June 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.
11. 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 results in widespread impact on the
market structure and requires participation and oversight of the Federal Energy
Regulatory Commission ("FERC"), the CPUC has sought to build a California
consensus involving the legislature, the Governor, public and municipal
utilities and customers. The consensus has resulted in filings with the FERC
which should permit both the CPUC and FERC to collectively proceed with
implementation of the new competitive market structure. On September 23, 1996,
state legislation was passed, AB 1890 (the "Bill"), which codified much of the
CPUC decision and directed the CPUC to proceed with implementation of
restructure 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. The proposed restructuring provides for
phased-in customer choice (direct access), development of a non-discriminatory
market structure, full recovery of utility stranded costs, 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. In May 1997, the CPUC ruled that all utility customers will be able to
choose their electricity supplier beginning January 1, 1998. 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
- 11 -
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1997
existing business or results of operations. 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.
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.
- 12 -
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Except for historical financial information contained herein, the matters
discussed in this quarterly report 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 and energy price fluctuations,
(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. The Company has interests in 17 power
generation facilities and steam fields having an aggregate capacity of 1,874
megawatts. 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 50% interests in two gas-fired
facilities with an aggregate capacity of 390 megawatts in Virginia and Florida.
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 currently expects to complete the acquisition upon the fulfillment
of all required conditions. However, there can be no assurances that the Company
will successfully complete this acquisition.
- 13 -
On June 23, 1997, the Company completed the acquisition of a 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 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 six months ended June
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. As scheduled by PG&E and in accordance with their respective
power sales agreements, the King City and Gilroy Power Plants did not generate
electricity during the four months ended April 30, 1997. As scheduled, both
power plants resumed operation on May 1, 1997.
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 six months ended June 30, 1997, such facilities
experienced a reduced amount of curtailment compared to the same periods in
1996. Due to an amendment to the power sales contracts executed in April 1997,
the Company currently does not expect curtailment during the remainder of the
term of the power sales agreements for these power plants.
- 14 -
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, 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).
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
1997 1996 1997 1996
--------- --------- --------- ---------
Power Plants
Electricity revenues
Energy $ 25,293 $ 19,022 $ 44,270 $ 34,362
Capacity $ 26,762 $ 18,208 $ 31,943 $ 19,774
Megawatt hours produced 552,057 408,413 820,666 739,088
Average energy rate per
kilowatt hour produced $ 0.0458 $ 0.0466 $ 0.0539 $ 0.0465
Steam Fields
Steam revenues $ 10,584 $ 9,025 $ 20,113 $ 17,895
Megawatt hours produced 672,233 485,389 1,279,071 1,041,428
Average energy rate per
kilowatt hour produced $ 0.0157 $ 0.0186 $ 0.0157 $ 0.0172
Electric energy and capacity revenue increased for the three and six months
ended June 30, 1997 compared to the same periods in 1996, primarily due to the
Gilroy and King City Power Plants.
Megawatt hours produced by power plants increased in 1997 compared to the same
periods in 1996, primarily due to 121,000 megawatt hours produced by the Gilroy
Power Plant for the three and six months ended June 30, 1997. The Gilroy Power
Plant was acquired by the Company in August 1996. During the six months ended
June 30, 1997, Greenleaf 1 Power Plant production declined by 51,000 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 declined for the three months ended
June 30, 1997 compared to the same period in 1996, primarily due to lower priced
Gilroy energy production. The average energy rate per kilowatt hour produced for
all power plants increased for the six months ended June 30, 1997 compared to
the same period in 1996, reflecting increases in the average energy prices per
kilowatt hour produced during 1997 at certain gas-fired power plants.
Steam field megawatt hours produced increased for the three and six months
ended June 30, 1997 compared to the same periods in 1996, primarily due to more
production and less curtailment during 1997. During 1996, PG&E Unit 13 was shut
down from March 23 to May 25 for installation of a new turbine rotor. In
addition, the SMUDGEO#1 power plant was shut down from April 21 to June 5, 1996
for a scheduled overhaul. The average
- 15 -
energy rates per kilowatt hour produced during 1997 were lower than the prices
for the comparable periods in 1996, primarily due to lower prices in accordance
with the power sales agreements.
OTHER FINANCIAL DATA AND RATIOS
Set forth below are certain other financial data and ratios for the periods
indicated (in thousands, except ratio data):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- --------------------------
1997 1996 1997 1996
----------- --------- --------- --------
Depreciation and amortization $ 12,216 $ 8,475 $ 23,548 $15,350
Interest expense per indenture $ 14,453 $ 11,528 $ 28,621 $20,081
EBITDA $ 43,218 $ 27,783 $ 62,697 $41,136
EBITDA to interest expense per indenture 2.99x 2.41x 2.19x 2.05x
EBITDA is defined as income from operations plus depreciation, capitalized
interest, other income, non-cash charges and cash received from investments in
power projects, reduced by the income from unconsolidated investments in power
projects. EBITDA is presented not as a measure of operating results, but rather
as a measure of 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 Six Months Ended June 30, 1997 Compared to Three and Six Months Ended
June 30, 1996
Revenue. Total revenue was $67.7 million and $107.0 million for the three and
six months ended June 30, 1997 compared to $50.3 million and $82.0 million for
the comparable periods in 1996. Electricity and steam sales revenue increased
35% and 34% to $62.6 million and $96.3 million for the three and six months
ended June 30, 1997 compared to $46.3 million and $72.0 million for the
comparable periods in 1996. The increase for the three months ended June 30,
1997 was primarily due to $11.0 million of revenue from the Gilroy Power Plant
acquired in August 1996, $1.4 million of higher revenue from the King City Power
Plant (included in Company operations since May 1996), and $3.4 million of
higher revenue from the Company's geothermal facilities. The increase for the
six months ended June 30, 1997 was primarily due to $13.5 million of revenue
from the Gilroy Power Plant, $2.6 million of higher revenue from the King City
Power Plant, $5.9 million of higher revenue from the Company's geothermal power
plants, and $2.4 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 $1.8 million and
$3.7 million for the three and six months ended June 30, 1997 compared to the
same periods in 1996, primarily due to increased kilowatt hour generation. The
West Ford Flat and Bear Canyon Power Plants were curtailed under their power
sales agreements for approximately $251,000 and $1.9 million of revenue during
the three and six months ended June 30, 1997, compared to approximately $2.3
million and $4.9 million of revenue during the same periods in 1996. Thermal
Power Company also contributed $859,000 and $1.8 million more revenue for the
three and six months ended June 30, 1997 than the same periods in 1996 due to
increased steam sales under the alternative pricing agreement entered into with
PG&E in March 1996. Service contract revenue decreased 39% and 35% to $1.7
million and $2.8 for the three and six months ended June 30, 1997 compared to
$3.5 and $5.4 million primarily due to overhauls at the Aidlin and Agnews power
plants during 1996. Income from unconsolidated investments in power projects
increased to $2.1 million and $4.2 million for the three and six months ended
June 30, 1997 compared to $298,000 and $1.7 million for the same periods in
1996. The increase is primarily attributable to increased equity income from the
Company's investment
- 16 -
in Sumas Cogeneration Company, L.P. ("Sumas"). The increase in Sumas income was
primarily due to lower operating costs in 1997 as the plant operated at minimum
capacity from February to June 1997 in accordance with the the power sales
agreement. However, Sumas also received a higher price for energy sold and
certain other payments from Puget Sound Power and Light Company under the power
sales agreement. In addition, operating costs were lower in 1997 Interest income
on loans to power projects increased 41% and 4% to $1.3 million and $3.0 million
for the three and six months ended June 30, 1997 compared to $920,000 and $2.8
million for the comparable periods in 1996, primarily related to interest income
on the loans to the sole shareholder of Sumas Energy, Inc., the Company's
partner in the Sumas project.
Cost of revenue. Cost of revenue increased 24% and 32% to $37.2 million and
$67.8 million for the three and six months ended June 30, 1997 compared to $30.0
million and $51.3 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 $3.9 million for the
three and six months ended June 30, 1997 compared to $894,000 and $1.4 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
increased 38% and 46% to $4.4 million and $8.6 million for the three and six
months ended June 30, 1997 compared to $3.2 million and $5.9 million for the
same periods 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 $13.2 million and $26.1 million
for the three and six months ended June 30, 1997 compared to $10.4 million and
$18.7 million for the comparable periods in 1996. The 27% increase for the three
months ended June 30, 1996 compared to the same period in 1996 was attributable
to $2.4 million of interest on debt related to the Gilroy Power Plant acquired
in August 1996 and $2.4 million of increased interest on the 10 1/2% Senior
Notes Due 2006 issued in May 1996, offset by $723,000 of interest capitalized
for the construction of the Pasadena Power Plant and a $1.5 million decrease in
interest expense primarily as a result of repayments of principal on certain
non-recourse project financings and other short-term borrowings. The 40%
increase for the six months ended June 30, 1997 compared to the same period in
1996 was attributable to $7.3 million of increased interest expense related to
the 10 1/2% Senior Notes Due 2006 issued in May 1996 and $4.7 million of
interest on debt related to the Gilroy Power Plant acquired in August 1996,
offset by $1.3 million of interest capitalized for the construction of the
Pasadena Power Plant and a $3.2 million decrease in interest expense primarily
as a result of repayments of principal on certain non-recourse project
financings and other short-term borrowings.
Other income, net. Other income, net increased to $4.3 million and $7.9 million
for the three and six months ended June 30, 1997 compared to $2.2 million and
$2.8 million for the same periods in 1996 due to 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 39%
and 36% for the three and six months ended June 30, 1997. The effective tax rate
differs from the federal statutory rate due to the effect of state tax rates
offset by depletion in excess of tax basis benefits at the Company's geothermal
facilities. The effective rate for the three and six months ended June 30, 1996
was 41% which approximates federal and state statutory tax rates.
- 17 -
LIQUIDITY AND CAPITAL RESOURCES
The following table summarizes the Company cash flow activities for the periods
indicated (in thousands):
Six Months Ended
June 30,
1997 1996
---------- ----------
Cash flows from:
Operating activities $ 16,800 $ 5,035
Investing activities (220,497) (126,051)
Financing activities 127,123 137,609
---------- ----------
Total $ (76,574) $ 16,593
========== ==========
Operating activities provided $16.8 million for the six months ended June 30,
1997 consisting of approximately $5.4 million of net income from operations,
$1.9 million in deferred income taxes, $21.8 million of depreciation and
amortization, $15.7 million net decrease in operating assets and liabilities,
$6.1 million partnership distribution from unconsolidated investments in power
projects and $1.6 million distribution from Coperlasa, offset by $4.2 million of
income from unconsolidated investments in power projects.
Investing activities used $220.5 million during the six months ended June 30,
1997, primarily due to $192.0 million for the acquisition of Texas Cogeneration
Company and the related notes receivable, $39.7 million of capital expenditures
related to the construction of the Pasadena Power Plant, $17.9 million of other
capital expenditures, $7.6 million for the acquisition of Calpine Gas Company,
offset by a $5.7 million loan payment from Texas City and Clear Lake Power
Plants, $5.3 million of collateral security maturities in connection with the
King City Power Plant and a $29.5 million decrease in restricted cash, primarily
related to the Pasadena Power Plant.
Financing activities provided $127.1 million of cash during the six months ended
June 30, 1997 consisting of $139.3 million of borrowings for the acquisition of
Texas Cogeneration Company and the related debt, $3.3 million of borrowings for
contingent consideration in connection with the acquisition of the Gilroy Power
Plant, offset by $15.9 million repayment of non-recourse project debt.
As of June 30, 1997, cash and cash equivalents were $23.4 million and working
capital was a negative $77.2 million. For the six months ended June 30, 1997,
cash and cash equivalents decreased by $76.6 million and working capital
decreased by $173.4 million as compared to the period ended December 31, 1996.
The decrease in working capital is primarily due to 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.
At June 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 9 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.
- 18 -
At June 30, 1997, the Company had $301.5 million of non-recourse project
financing associated with power generating facilities and steam fields at the
West Ford Flat Power Plant, the Bear Canyon Power Plant, the PG&E Unit 13 and
Unit 16 Steam Fields, the SMUDGEO #1 Steam Fields, the Greenleaf 1 and 2 Power
Plants and the Gilroy Power Plant. Utilizing a portion of the net proceeds from
the sale of the 8 3/4% Senior Notes Due 2007, on July 8, 1997 the Company
extinguished $102.7 million of non-recourse project financing related to the
Company's geothermal assets. After such early extinguishment, the annual
maturities for all non-recourse project financing were $8.3 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 $149.8 million thereafter.
At June 30, 1997, the Company had $119.3 million of non-recourse borrowings from
The Bank of Nova Scotia in connection with the acquisition of 50% equity
interests in the Texas City and Clear Lake Power Plants. Such debt matures on
June 22, 1998 and is expected to be repaid prior to maturity with the proceeds
of a planned refinancing of the $155.6 million non-recourse project debt owed by
the Texas City and Clear Lake Power Plants.
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 June 30, 1997, the Company had $14.3
million of borrowings outstanding and $2.7 million of letters of credit
outstanding under the revolving credit facility (see Note 7). The Company repaid
the $14.3 million of borrowings on July 8, 1997. 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 June 30, 1997, the Company had no borrowings under this working
capital line and $974,000 of letters of credit outstanding. Borrowings bear
interest at prime plus 1%.
At June 30, 1997, the Company had outstanding a non-interest bearing promissory
note to Natomas Energy Company in the amount of $6.5 million representing a
portion of the September 1994 purchase price of Thermal Power Company. This note
had been discounted to yield 8% per annum and was due September 9, 1997. On July
10, 1997, the Company extinguished this debt with the payment of $6.4 million
(see Note 9).
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 June 30, 1996, the Company had commitments for capital expenditures in 1997
totaling $44.2 million related to various projects at its geothermal 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 six months
ended June 30, 1997 of $57.6 million included $39.7 million for the construction
of the Pasadena Power Plant, $8.2 million related to the geothermal facilities
and the remaining $9.7 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.
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 December 31, 1997.
- 19 -
Impact of Recent Accounting Pronouncement
In February 1997, the FASB issued SFAS No. 128, Earnings Per Share, which
simplifies the standards for computing earnings per share previously found in
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 months ended June 30, 1997, basic and
diluted earnings per share would not be materially different to the earnings per
share presented in the accompanying condensed consolidated statement of
operations.
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
The Company's Annual Meeting of Stockholders was held on June 5, 1997 (the
"Annual Meeting") in San Jose, California. At the Annual Meeting, stockholders
voted on two matters: (i) the election of three Class I directors for a term of
three years expiring in 2000 and (ii) the ratification of the appointment of
Arthur Andersen LLP as independent auditors for the Company for the year ending
December 31, 1997. The stockholders elected management's nominees as the Class I
directors in an uncontested election and ratified the appointment of independent
auditors by the following votes, respectively:
- 20 -
(i) Election of Class I directors for a three year term expiring in 2000:
Votes Votes
For Withheld
--------------- --------------
Jeffrey E. Garten 13,404,368 18,815
George J. Stathakis 13,403,700 19,483
John O. Wilson 13,404,568 18,615
The Company's Board of Directors is currently comprised of seven members
that are divided into three classes with overlapping three-year terms. The
term of the Class II directors (Ann B. Curtis and V. Orville Wright) will
expire at the annual meeting of stockholders to be held in 1998, and the
Class III directors (Peter Cartwright and Susan C. Schwab) will expire at
the annual meeting to be held in 1999.
(ii) Ratification of appointment of Arthur Andersen LLP as independent auditors:
Votes Votes
For Against Abstain
--------------- -------------- --------------
13,384,188 913 38,082
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
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)
- 21 -
4.3 Indenture dated as of July 8, 1997, between Calpine Corporation and The
Bank of New York, as Trustee, including form of Notes. *
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. *
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)
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)
- 22 -
10.1.13 Project Credit Agreement, dated as of June 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. *
10.1.19 Purchase agreement dated as of July 1, 1997, among Calpine Corporation
and The Bank of New York as the Trustee. *
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. *
10.3 Power Sales Agreements
10.3.1 Long-Term Energy and Capacity Power Purchase Agreement relating to the
Bear Canyon Facility, dated November 30, 1984, between Pacific Gas &
Electric and Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.), Amendment dated October 17, 1985, Second
Amendment dated October 19, 1988, and related documents. (a)
10.3.2 Long-Term Energy and Capacity Power Purchase Agreement relating to the
Bear Canyon Facility, dated November 29, 1984, between Pacific Gas &
Electric and Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.), and Modification dated November 29, 1984,
Amendment dated October 17, 1985, Second Amendment dated October 19,
1988, and related documents. (a)
- 23 -
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)
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)
- 24 -
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)
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)
- 25 -
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)
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)
- 26 -
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)
------------------------------------
* Filed herewith.
(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 June 30, 1995 and filed on May 12, 1995.
(g) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 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 June 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).
- 27 -
(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 June 30, 1997.
(o) Incorporated by reference to Registrants Quarterly Report on Form 10-Q
dated March 31, 1997 and filed on May 12, 1997.
(b) Reports on Form 8-K
Current report dated June 5, 1997 and filed on June 17, 1997
Item 5. Other Events -- Preferred Share Purchase Rights
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
Ite 5. Other Events -- Pricing of Rule 144A offering of
$200.0 million principal amount of 8-3/4% Senior
Notes Due 2007
- 28 -
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CALPINE CORPORATION
By: /s/ Ann B. Curtis Date: August 13, 1997
-------------------------------
Ann B. Curtis
Senior Vice President
(Chief Financial Officer)
By: /s/ Gloria S. Gee Date: August 13, 1997
------------------------------
Gloria S. Gee
Corporate Controller
(Chief Accounting Officer)
- 29 -
EXHIBIT INDEX
Exhibit
Number Description
11 Computation of Earnings Per Share
27 Financial Data Schedule
4.3 Indenture dated as of July 8, 1997, between Calpine
Corporation and The Bank of New York, as Trustee,
including form of Notes.
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.
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.
10.1.19 Purchase agreement dated as of July 1, 1997, among Calpine
Corporation and The Bank of New York as the Trustee.
10.2.6 Purchase and Sale Agreement dated March 27, 1997
between Enron Power Corp. and Calpine Finance Company.
- 30 -