<PAGE>
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 March 31, 1999
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 for the transition period from _______________________ to
______________________
Commission File Number: 033-73160
CALPINE CORPORATION
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date: $0.001 par value Common Stock
27,169,147 shares outstanding on May 11, 1999.
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q
For the Quarter Ended March 31, 1999
INDEX
PART I. FINANCIAL INFORMATION Page No.
ITEM 1. Financial Statements
Consolidated Balance Sheets
March 31, 1999 and December 31, 1998 ....................... 3
Consolidated Statements of Operations
Three Months Ended March 31, 1999 and 1998 ................. 4
Consolidated Statements of Cash Flows
Three Months Ended March 31, 1999 and 1998 ................. 5
Notes to 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 ................................. 23
ITEM 2. Change in Securities .............................. 24
ITEM 3. Defaults Upon Senior Securities ................... 24
ITEM 4. Submission of Matters to a Vote of Security Holders 24
ITEM 5. Other Information ................................. 24
ITEM 6. Exhibits and Reports on Form 8-K .................. 24
Signatures .......................................................... 28
2
<PAGE>
PART 1. FINANCIAL STATEMENTS
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, 1999 and December 31, 1998
(in thousands)
<TABLE>
<CAPTION>
March 31, December 31,
1999 1998
----------- ------------
(unaudited)
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents ............................................ $ 698,957 $ 96,532
Accounts receivable from related parties ............................. 2,748 4,115
Accounts receivable .................................................. 68,024 79,743
Inventories .......................................................... 15,268 14,194
Other current assets ................................................. 14,702 14,919
---------- ----------
Total current assets ......................................... 799,699 209,503
---------- ----------
Property, plant and equipment, net ..................................... 1,279,308 1,094,303
Investments in power projects .......................................... 239,172 221,509
Project development costs .............................................. 33,032 17,001
Collateral securities, net of current portion .......................... 85,531 86,920
Notes receivable from related parties .................................. 15,624 10,899
Restricted cash ........................................................ 21,244 14,454
Deferred financing costs ............................................... 32,131 22,789
Other assets ........................................................... 56,813 51,568
---------- ----------
Total assets ................................................. $2,562,554 $1,728,946
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Non-recourse project financing, current portion ...................... $ 5,450 $ 5,450
Accounts payable ..................................................... 50,782 53,190
Accrued interest payable ............................................. 30,165 25,600
Other current liabilities ............................................ 35,340 38,339
---------- ----------
Total current liabilities .................................... 121,737 122,579
---------- ----------
Non-recourse project financing, net of current portion ................. 115,150 114,190
Notes payable .......................................................... 47,570 --
Senior notes ........................................................... 1,551,348 951,750
Deferred income taxes, net ............................................. 162,061 159,788
Deferred lease incentive ............................................... 66,922 67,814
Other liabilities ...................................................... 27,461 25,859
---------- ----------
Total liabilities ............................................ 2,092,249 1,441,980
---------- ----------
Stockholders' equity:
Preferred stock, $0.001 par value per share:
authorized 10,000,000 shares, none issued
and outstanding in 1999 and 1998 ................................. -- --
Common stock, $0.001 par value per share:
authorized 100,000,000 shares; issued and
outstanding 26,267,297 in 1999 and
20,161,581 in 1998 ............................................... 26 20
Additional paid-in capital ........................................... 348,357 168,874
Retained earnings .................................................... 121,922 118,072
---------- ----------
Total stockholders' equity ................................... 470,305 286,966
---------- ----------
Total liabilities and stockholders' equity ................... $2,562,554 $1,728,946
========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
3
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 1999 and 1998
(in thousands, except per share amounts)
(unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
----------------------
1999 1998
--------- ---------
<S> <C> <C>
Revenue:
Electricity and steam sales ............................ $ 128,026 $ 43,390
Service contract revenue from related parties .......... 6,772 5,481
Income from unconsolidated investments in power projects 10,812 3,754
Interest income on loans to power projects ............. 303 2,520
--------- ---------
Total revenue ....................................... 145,913 55,145
--------- ---------
Cost of revenue:
Plant operating expenses ............................... 23,136 10,272
Fuel expense ........................................... 53,937 5,671
Depreciation ........................................... 18,979 12,350
Production royalties ................................... 2,417 2,872
Operating lease expenses ............................... 5,593 3,308
Service contract expenses .............................. 5,445 4,896
--------- ---------
Total cost of revenue ............................... 109,507 39,369
--------- ---------
Gross profit ............................................. 36,406 15,776
Project development expenses ............................. 1,956 1,681
General and administrative expenses ...................... 10,031 5,236
--------- ---------
Income from operations .............................. 24,419 8,859
Interest expense ......................................... 21,027 18,523
Interest income .......................................... (2,778) (2,363)
Other income ............................................. (163) (401)
--------- ---------
Income (loss) before provision for income taxes ..... 6,333 (6,900)
Provision for (benefit from) income taxes ................ 2,483 (3,843)
--------- ---------
Net income (loss) ................................... $ 3,850 $ (3,057)
========= =========
Basic earnings per common share:
Weighted average shares of common stock ................ 20,595 20,087
Basic earnings per share ............................... $ 0.19 $ (0.15)
Diluted earnings per common share:
Weighted average shares of common stock ................ 21,945 20,087
Diluted earnings per share ............................. $ 0.18 $ (0.15)
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
4
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 1999 and 1998
(in thousands)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
----------------------
1999 1998
--------- ---------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss) ........................................ $ 3,850 $ (3,057)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization ......................... 19,379 12,538
Deferred income taxes, net ............................ 2,273 (3,793)
Income from unconsolidated investments in power projects (10,812) (3,754)
Distributions from unconsolidated power projects ...... 10,272 5,962
Change in operating assets and liabilities:
Accounts receivable ................................. 13,086 20,559
Inventories ......................................... (324) 429
Other current assets ................................ 1,243 2,355
Other assets ........................................ (6,414) (8,628)
Accounts payable and accrued expenses ............... (824) (19,940)
Other liabilities ................................... 1,650 874
--------- ---------
Net cash provided by operating activities ........ 33,379 3,545
--------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment ............. (104,350) (12,873)
Acquisitions ............................................. (116,957) (157,108)
Decrease in notes receivable ............................. -- 13,814
Maturities of collateral securities ...................... 1,850 4,480
Project development costs ................................ (17,629) (2,912)
Increase in restricted cash .............................. (6,789) (76)
Other .................................................... (4,725) 419
--------- ---------
Net cash used in investing activities ............ (248,600) (154,256)
--------- ---------
Cash flows from financing activities:
Borrowings from non-recourse project financing ........... 176,155 44,450
Repayments of non-recourse project financing ............. (127,625) (140,935)
Proceeds from issuance of Senior Notes ................... 600,000 300,000
Proceeds from issuance of common stock ................... 177,900 421
Financing costs .......................................... (8,784) (4,778)
--------- ---------
Net cash provided by financing activities ........ 817,646 199,158
--------- ---------
Net increase in cash and cash equivalents .................. 602,425 48,447
Cash and cash equivalents, beginning of period ............. 96,532 48,513
--------- ---------
Cash and cash equivalents, end of period ................... $ 698,957 $ 96,960
========= =========
Cash paid during the period for:
Interest ................................................. $ 19,365 $ 23,034
Income taxes ............................................. $ 1,175 $ --
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
5
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 1999
1. Organization and Operation of the Company
Calpine Corporation, a Delaware corporation, and subsidiaries (collectively, the
"Company") is engaged in the development, acquisition, ownership, and operation
of power generation facilities and the sale of electricity and steam in the
United States and selected international markets. The Company has ownership
interests in and operates gas-fired cogeneration facilities, geothermal
steam fields and geothermal power generation facilities in northern
California, Washington, Texas and various locations on the East Coast. Each of
the generation facilities produces electricity which is marketed to utilities
and other third party purchasers. Thermal energy produced by the gas-fired
cogeneration facilities is primarily sold to governmental and industrial users.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying interim consolidated financial
statements of the Company have been prepared by the Company, without audit by
independent public accountants, pursuant to the rules and regulations of the
Securities and Exchange Commission. In the opinion of management, the
consolidated financial statements include the adjustments necessary to present
fairly the information required to be set forth therein. Certain information and
note disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles have been condensed or
omitted from these statements pursuant to such rules and regulations and,
accordingly, should be read in conjunction with the audited consolidated
financial statements of the Company included in the Company's annual report on
Form 10-K for the year ended December 31, 1998. The results for interim periods
are not necessarily indicative of the results for the entire year.
Capitalized interest -- The Company capitalizes interest on projects during the
construction period. For the three months ended March 31, 1999 and 1998, the
Company capitalized $3.8 million and $2.0 million, respectively, of interest in
connection with the construction of power plants.
Derivative financial instruments -- The Company engages in activities to manage
risks associated with changes in interest rates. The Company has entered into
swap agreements to reduce exposure to interest rate fluctuations in connection
with certain debt commitments. The instruments' cash flows mirror those of the
underlying exposures. Unrealized gains and losses relating to the instruments
are being deferred over the lives of the contracts. The premiums paid on the
instruments, as measured at inception, are being amortized over their respective
lives as components of interest expense. Any gains or losses realized upon the
early termination of these instruments are deferred and recognized in income
over the remaining life of the existing swap.
New Accounting Pronouncements -- In June 1997, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 131, "Disclosures about Segments of an Enterprise and Related
Information." This Statement establishes the reporting of information about
operating segments in annual financial statements and requires that 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.
During 1998, the Company started the process of decentralization of its
operations and completed this process during the first quarter of calendar 1999.
The Company has adopted this pronouncement beginning January 1999 (see Note 5).
In June 1998, FASB also issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". This Statement establishes accounting and
reporting standards, requiring every derivative instrument be recorded in the
balance sheet as either an asset or liability measured at its fair value. This
6
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
March 31, 1999
statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and require
that a company formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999. This
Statement must be applied to derivative instruments and to certain derivative
instruments embedded in hybrid contracts that were issued, acquired, or
substantively modified after December 31, 1997. The Company has not yet analyzed
the impact of adopting SFAS No. 133 on the financial statements and has not
determined the timing of or method of the adoption of SFAS No. 133. However,
this Statement could increase volatility in earnings.
Reclassifications -- Prior period amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1999
presentation.
3. Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
<TABLE>
<CAPTION>
March 31, December 31,
1999 1998
----------- -----------
<S> <C> <C>
Geothermal properties ............................. $ 412,604 $ 312,139
Buildings, machinery and equipment ................ 670,618 653,865
Power sales agreements ............................ 145,957 145,957
Gas contracts ..................................... 122,561 122,561
Other assets ...................................... 20,593 18,955
----------- -----------
1,372,333 1,253,477
Less accumulated depreciation and amortization .... (215,660) (203,984)
----------- -----------
1,156,673 1,049,493
Land .............................................. 1,590 1,590
Construction in progress .......................... 121,045 43,220
----------- -----------
Property, plant and equipment, net ................ $ 1,279,308 $ 1,094,303
=========== ===========
</TABLE>
Construction in progress includes costs primarily attributable to the purchase
of gas-fired turbines for projects currently under development.
4. Results of Unconsolidated Investments in Power Projects
The Company has unconsolidated investments in power projects which are accounted
for under the equity method. Investments in less-than-majority-owned affiliates
and the nature and extent of these investments change over time. The combined
results of operations and financial positions of the Company's equity-basis
affiliates are summarized below (in thousands):
<TABLE>
<CAPTION>
Three Months Ended
March 31,
1999 1998
---------- -----------
<S> <C> <C>
Condensed Statement of Operations:
Revenue .......................................... $ 193,133 $ 190,815
Net income ....................................... $ 47,491 $ 13,236
Company's share of net income .................... $ 10,812 $ 3,754
March 31, December 31,
1999 1998
---------- -----------
Condensed Balance Sheet:
Assets ........................................... $1,338,508 $1,274,202
Liabilities ...................................... $1,043,010 $1,000,812
</TABLE>
The following details the Company's income from investments in unconsolidated
power projects and the service contract revenue recorded by the Company related
to those power projects (in thousands):
7
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
March 31, 1999
<TABLE>
<CAPTION>
Service
Ownership Income Contract Revenue
Interest For the three months ended March 31,
1999 1998 1999 1998
------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Sumas Power Plant ................. -- $ 8,243 $ 978 $ 932 $ 373
Gordonsville Power Plant .......... 50% 1,345 1,367 -- --
Lockport Power Plant .............. 11.4% 1,068 938 -- --
Texas Cogeneration Company ........ -- -- 2,922 -- 1,613
Bayonne Power Plant ............... 7.5% 1,156 -- -- --
Kennedy International Airport Power 50% (1,038) (2,192) 239 --
Plant
Aidlin Power Plant ................ 5% 88 111 663 802
Stony Brook Power Plant ........... 50% (78) (119) 239 --
Agnews Power Plant ................ 20% 65 (88) 430 437
Auburndale Power Plant ............ 50% (37) (163) -- --
------- ------- ------- -------
Total ................... $10,812 $ 3,754 $ 2,503 $ 3,225
======= ======= ======= =======
</TABLE>
5. Information by Operating Segment
The Company, which operates in a single industry segment, develops, acquires,
owns and operates power generation facilities for the sale of electricity and
steam within the United States and selected international markets. Operating
segments are defined as components of an enterprise about which separate
financial information is available and that is evaluated regularly by the chief
operating decision maker, or decision making group, in deciding how to allocate
resources and in assessing performance. The Company's chief operating
decision-making group is comprised of the Chief Executive Officer and other
senior management.
The Company's reportable segments are strategic regions which include the
Western, Central, and Eastern Regions along with Corporate Headquarters. The
Company in early 1998, determined that in order to meet the needs of its
customers as well as take advantage of deregulated markets in the United States,
it would need to manage its business geographically. These four reportable
segments have been determined by geographical boundaries as well as where the
Company is currently operating power generation facilities, or has development
projects and/or projects in construction. The Western Region's boundaries are
from Washington State to the New Mexico border, including selected international
markets. The Central Region is primarily responsible for the Texas operations as
well as development projects throughout the Midwest. The Eastern Region's
primary area of responsibility is for the Eastern states from Florida to Maine,
with the Corporate Headquarters primarily responsible for overall strategic
decision making and construction activities.
The Company evaluates performance based upon several criteria including after
tax profits, which is identified as segment net income. The accounting policies
of the reportable segments are the same as those described in the summary of
significant accounting policies. The financial results for the Company's four
reportable segments have been prepared on a basis consistent with the manner in
which the Company's management internally disaggregates financial information
for the purposes of assisting in making internal operating decisions. In this
regard, certain common expenses have been allocated less precisely than would be
required for the stand-alone information prepared in accordance with generally
accepted accounting principles. Revenue attributed to the geographic areas is
based on the location of the customer.
8
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
March 31, 1999
<TABLE>
<CAPTION>
(in thousands)
Western Central Eastern Corporate Total
Reportable Segments Region Region Region Headquarters Segments
- --------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 1999
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Electricity and steam sales $ 39,858 $ 80,317 $ 7,851 $ -- $ 128,026
Income from unconsolidated investments 8,396 1,156 1,260 -- 10,812
Other revenues 6,160 437 478 -- 7,075
------------ ----------- ------------ ------------- ------------
Segment total revenues 54,414 81,910 9,589 -- 145,913
Depreciation and amortization 9,867 8,467 645 -- 18,979
Other costs of revenue 36,393 48,367 5,868 (100) 90,528
------------ ----------- ------------ ----------- ------------
Gross operating profit 8,154 25,076 3,076 100 36,406
Project development expenses 131 181 160 1,484 1,956
General and administrative expenses 1,520 964 382 7,165 10,031
------------ ----------- ------------ ----------- ------------
Income (loss) from operations 6,503 23,931 2,534 (8,549) 24,419
Interest expense (1) 2,583 331 (2,363) 20,476 21,027
Interest income (1,886) (103) (42) (747) (2,778)
Other (income) expense (79) 49 (22) (111) (163)
------------ ----------- ------------ ----------- ------------
Income (loss) before provision for
income taxes 5,885 23,654 4,961 (28,167) 6,333
Provision for (benefit from) income taxes 2,235 8,972 446 (9,170) 2,483
------------ ----------- ------------ ------------- ------------
Segment net income (loss) $ 3,650 $ 14,682 $ 4,515 $ (18,997) $ 3,850
============ =========== ============ ============= ============
Segment assets $ 637,721 $ 248,679 $ 203,998 $ 1,472,156 $ 2,562,554
Capital expenditures (2) 2,676 23,497 99 -- 26,272
Construction of new projects (2) -- 48,872 -- 29,206 78,078
- --------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 1998
- --------------------------------------------------------------------------------------------------------------------
Electricity and steam sales $ 38,490 $ -- $ 4,900 $ -- $ 43,390
Income from unconsolidated investments 1,000 2,922 (168) -- 3,754
Other revenues 1,951 4,134 1,916 -- 8,001
------------ ----------- ------------ ------------- ------------
Segment total revenues 41,441 7,056 6,648 -- 55,145
Depreciation and amortization 12,077 -- 273 -- 12,350
Other costs of revenue 20,149 1,277 5,593 -- 27,019
------------ ----------- ------------ ----------- ------------
Gross operating profit 9,215 5,779 782 -- 15,776
Project development expenses -- -- -- 1,681 1,681
General and administrative expenses 629 149 5 4,453 5,236
------------ ----------- ------------ ----------- ------------
Income (loss) from operations 8,586 5,630 777 (6,134) 8,859
Interest expense 4,042 788 67 13,626 18,523
Interest income (1,859) (125) (285) (94) (2,363)
Other (income) expense -- -- -- (401) (401)
------------ ----------- ------------ ----------- ------------
Income (loss) before provision for
income taxes 6,403 4,967 995 (19,265) (6,900)
Provision for (benefit from) income taxes 2,554 1,826 380 (8,603) (3,843)
------------ ----------- ------------ ----------- ------------
Segment net income (loss) $ 3,849 $ 3,141 $ 615 $ (10,662) $ (3,057)
============ =========== ============ ============= ============
Segment assets $ 615,694 $ 169,764 $ 14,549 $ 878,090 $ 1,678,097
Capital expenditures (2) 3,740 -- -- -- 3,740
Construction of new projects (2) -- 6,892 -- 2,241 9,133
</TABLE>
(1)-- Interest expense for the Eastern Region reflects interest capitalized for
the three months ended March 31, 1999.
(2)-- Capital expenditures are defined as capital purchases for the Company's
existing portfolio of power plants. Construction of new projects is defined as
capital purchases related to the development of new power plants.
6. Common Stock and Senior Notes Offering
On March 26, 1999, the Company completed a public offering of 6,000,000 shares
of its common stock at $31.00 per share. The net proceeds from this public
offering are estimated to be approximately $177.9 million. Additionally, in
April 1999, the Company sold an additional 900,000 shares of common stock at
9
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
March 31, 1999
$31.00 per share pursuant to the exercise of the underwriters' over-allotment
option for net proceeds of approximately $26.7 million.
On March 29, 1999, the Company completed a public offering of $250 million of
its 7-5/8% Senior Notes Due 2006 ("Senior Notes Due 2006") and $350 million of
its 7-3/4% Senior Notes Due 2009 ("Senior Notes Due 2009"). The Senior Notes due
2006 bear interest at 7-5/8% per year, payable semi-annually on April 15 and
October 15 each year and mature on April 15, 2006. The Senior Notes due 2006 are
not redeemable prior to maturity. The Senior Notes due 2009 bear interest at
7-3/4% per year, payable semi-annually on April 15 and October 15 each year and
mature on April 15, 2009. The Senior Notes due 2009 are not redeemable prior to
maturity. After deducting underwriting discounts and expenses of the offering,
the aggregate net proceeds from the sale of the Senior Notes were approximately
$589.6 million.
The net proceeds from the sale of the common stock, the Senior Notes Due 2006,
and the Senior Notes Due 2009 will be used as follows: (i) $119.6 million to
refinance indebtedness relating to the Gilroy Power Plant, (ii) $77.6 million to
repay indebtedness under a bridge facility provided by Credit Suisse First
Boston to finance a portion of the purchase price to acquire the steam fields
that service the Sonoma Power Plants, (iii) $50.0 million to repay outstanding
borrowings under our revolving credit facility, $23.4 million of which was
incurred to finance a portion of the steam fields that service the Sonoma Power
Plants, (iv) $25.0 million to complete the expansion of the Clear Lake Power
Plant, and (v) approximately $400.0 million to finance a portion of power
generation facilities currently under construction and the projects currently
under development. Transaction costs incurred in connection with the Senior
Notes offering were recorded as a deferred charge and are amortized over the
respective lives of the Senior Notes Due 2006 and the Senior Notes Due 2009
using the effective interest rate method.
7. Acquisitions
Unocal Transaction
On March 19, 1999, the Company completed the acquisition of Unocal Corporation's
Geysers geothermal steam fields in northern California for approximately $102.1
million. The steam fields fuel Pacific Gas & Electric Company's ("PG&E") 12
Sonoma County power plants, totaling 544 megawatts of capacity. The Company
purchased these plants on May 7, 1999 (see Note 12).
8. Non-recourse Project Financing
On January 4, 1999, the Company entered into a Credit Agreement with ING (U.S.)
Capital LLC to provide up to $265.0 million of non-recourse project financing
for the construction of the Pasadena facility expansion. As of March 31, 1999,
$47.6 million was outstanding under the agreement. The outstanding loan bears
interest at ING's base rate or at LIBOR plus an applicable margin and is payable
quarterly. The loan matures 15 years after completion of construction. In
connection with the Credit Agreement, the Company entered into a $10.0 million
letter of credit facility. At March 31, 1999, there were no letters of credit
outstanding under the facility.
9. Revolving Credit Facility and Line of Credit
The Company maintains a credit facility of $100.0 million, which is available
through a consortium of commercial lending institutions with The Bank of Nova
Scotia as agent. A maximum of $50.0 million of the credit facility may be
allocated to letters of credit. At March 31, 1999, the Company had no borrowings
and $21.9 million of letters of credit outstanding under the credit facility.
Borrowings bear interest at The Bank of Nova Scotia's base rate plus an
applicable margin or at LIBOR plus an applicable margin. Interest is paid on the
last day of each interest period for such loans, at least quarterly. The credit
facility specifies that the Company maintain certain covenants, with which the
Company was in compliance as of March 31,
10
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
March 31, 1999
1999. Commitment fees related to this line of credit are charged based on 0.375%
of committed unused credit.
At March 31, 1999, the Company had a loan facility with Union Bank with
available borrowings totaling $1.1 million. As of March 31, 1999, the Company
had no borrowings and $74,000 of letters of credit outstanding under the
facility.
Additionally, the Company had a $12.0 million letter of credit outstanding with
The Bank of Nova Scotia to secure performance of the Clear Lake Power Plant.
10. Earnings per Share
Basic earnings per share were computed by dividing net earnings by the weighted
average number of common shares outstanding for the period. The dilutive effect
of the potential exercise of outstanding options to purchase shares of common
stock is calculated using the treasury stock method. The reconciliation of basic
earnings per share to diluted earnings per share is shown in the following table
(dollars in thousands except share data):
<TABLE>
<CAPTION>
Periods Ended March 31, 1999 1998
--------------------------------- ---------------------------------
Net Net
Income Shares EPS Income Shares EPS
- -------------------------------------------------------------------------------------------------------------------
Three Months:
Basic earnings per common share:
<S> <C> <C> <C> <C> <C> <C>
Basic earnings per share $ 3,850 20,595 $ 0.19 $ (3,057) 20,087 $ (0.15)
========= ======= =========== ========
Common shares issuable upon
Exercise of stock options using
treasury stock method 1,350 --
------ ------
Diluted earnings per common share
Diluted earnings per share $ 3,850 21,945 $ 0.18 $ (3,057) 20,087 $ (0.15)
========= ====== ======= =========== ====== ========
</TABLE>
Unexercised employee stock options to purchase 23,000 and 2.1 million shares of
the Company's common stock during the three months ended March 31, 1999 and
1998, respectively, were not included in the computation of diluted shares
outstanding because such inclusion would be anti-dilutive.
11. Commitments and Contingencies
Production Royalties and Leases -- The Company is committed under several
geothermal leases and right-of-way, easement and surface agreements. The
geothermal leases generally provide for royalties based on production revenue
with reductions for property taxes paid. The right-of-way, easement and surface
agreements are based on flat rates and are not material. Under the terms of
certain geothermal leases, royalties accrue at rates ranging from 7% to 12.5% of
steam and effluent revenue. Certain properties also have net profits and
overriding royalty interests ranging from approximately 1.45% to 28%, which are
in addition to the land royalties. Most lease agreements contain clauses
providing for minimum lease payments to lessors if production temporarily ceases
or if production falls below a specified level.
The Company leases its corporate offices and regional offices in Boston,
Massachusetts, Houston, Texas, San Jose, California and Pleasanton, California,
under noncancellable operating leases expiring through 2002. Future minimum
lease payments under these leases for the remainder of 1999 are approximately
$1.5 million.
Natural Gas Purchases -- The Company enters into short-term gas purchase
contracts with third parties to supply gas to its gas-fired cogeneration
projects.
Capital expenditures -- At March 31, 1999, the Company is under contract with
Siemens Westinghouse Power Corporation for a total of $814.9 million for the
purchase of 23 turbines related to 11 development projects. Approximate payments
related to these turbines is $369.1 million for 1999.
11
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
March 31, 1999
Litigation
On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund
("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and
certain other parties, including the Company. Some of Indeck's claims relate to
Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville
Energy L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s
acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck claimed that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. In April 1999, the court granted Calpine Gordonsville
and Calpine Auburndale's motions to dismiss with prejudice. The Company is
unable to predict the outcome of these proceedings.
There is currently a dispute between Texas-New Mexico Power Company ("TNP") and
Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear Lake
Power Plant, regarding certain costs and other amounts that TNP has withheld
from payments due under the power sales agreement from August 1997 until October
1998. TNP has withheld approximately $450,000 per month related to transmission
charges. In October 1997, CLC filed a petition for declaratory order with the
Texas Public Utilities Commission ("Texas PUC") requesting a declaration that
TNP's withholding is in error, which petition is currently pending. Also, as of
March 31, 1999, TNP has withheld approximately $7.7 million of standby power
charges. In addition to the Texas PUC petition, CLC filed an action in Texas
courts on October 2, 1997, alleging TNP's breach of the power sales agreement
and is seeking refund of the standby charges. In October 1998, TNP and CLC
reached an agreement in principle to settle all outstanding disputes. The
parties have finalized the settlement documentation which has been submitted for
approval by the Texas PUC. Both the Texas PUC action and the court action have
been put on hold pending completion of the settlement. The Company does not
believe this will have a material adverse effect on the consolidated
financial statements.
An action was filed against Lockport Energy Associates, L.P. ("LEA") and the New
York Public Service Commission ("NYPSC") in August 1997 by New York State
Electricity and Gas Company ("NYSEG") in the Federal District Court for the
Northern District of New York. NYSEG has requested the Court to direct NYPSC and
the Federal Energy Regulatory Commission (the "FERC") to modify contract rates
to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a
cross-claim alleging that the FERC violated the Public Utility Regulatory
Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by failing
to reform the NYSEG contract that was previously approved by the NYPSC. Although
it is unable to predict the outcome of this case, in any event, the Company
retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase
the Company's interest in the Lockport Power Plant for $18.9 million, less
equity distributions received by the Company, at any time before December 19,
2001.
The Company is involved in various other claims and legal actions arising out of
the normal course of business. The Company does not expect that the outcome of
these proceedings will have a material adverse effect on the Company's financial
position or results of operations, although no assurance can be given in this
regard.
12. Subsequent Event
On May 7, 1999, the Company completed the acquisition from PG&E, of 12 Sonoma
County and 2 Lake County power plants located at The Geysers, California for
approximately $212.8 million. The acquisition was financed with a 24 year
operating lease. The Company's geothermal steam fields fuel the facilities,
which have a combined capacity of approximately 700 megawatts of electricity.
All of the electricity generated from the facilities is sold into the California
energy market, with the exception of an agreement entered into on April 29, 1999
to sell to Commonwealth Energy Corporation 75 megawatts of geothermal
electricity in 1999, 100 megawatts in 2000, and 125 megawatts in 2001 and
through June 2002.
12
<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 may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding our intent, belief or current
expectations. Prospective investors are cautioned that any such forward-looking
statements are not guarantees of future performance and involve a number of
risks and uncertainties; actual results could differ materially from those
indicated by such forward-looking statements. Among the important factors that
could cause actual results to differ materially from those indicated by such
forward-looking statements are: (i) that the information is of a preliminary
nature and may be subject to further adjustment, (ii) the possible
unavailability of financing, (iii) risks related to the development,
acquisition, and operation of power plants, (iv) the impact of avoided cost
pricing, energy price fluctuations and gas price increases, (v) the impact of
curtailment, (vi) the seasonal nature of our business, (vii) start-up risks,
(viii) general operating risks, (ix) the dependence on third parties, (x) risks
associated with international investments, (xi) risks associated with the power
marketing business, (xii) changes in government regulation, (xiii) the
availability of natural gas, (xiv) the effects of competition, (xv) the
dependence on senior management, (xvi) volatility in our stock price, (xvii)
fluctuations in quarterly results and seasonality, and (xviii) other risks
identified from time to time in our reports and registration statements filed
with the Securities and Exchange Commission.
Overview
Calpine is engaged in the development, acquisition, ownership, and operation of
power generation facilities and the sale of electricity and steam principally in
the United States. At March 31, 1999, we had interests in 22 powe plants and
three steam fields predominantly in the United States, having an aggregate
capacity of 3,018 megawatts.
On January 4, 1999, we completed the acquisition of a 20% interest in 82 billion
cubic feet of proven natural gas reserves located in the Sacramento basin of
Northern California. We paid approximately $14.9 million for $13.0 million in
redeemable non-voting preferred stock and 20% of the outstanding common stock of
Sheridan California Energy, Inc ("SCEI"). Additionally, we have signed a ten
year gas contract enabling us to purchase 100% of SCEI's production.
On February 17, 1999, we announced that the Delta Energy Center has met the
California Energy Commission's Data Adequacy requirements. This ruling stated
that our Application for Certification contained adequate information for the
California Energy Commission to begin their analysis of the power plant's
environmental impacts and proposed mitigation. The Delta Energy Center, an 880
megawatt gas-fired power plant located at the Dow Chemical facility in
Pittsburg, California, is the first power plant that will be developed, owned
and operated under a joint venture with Bechtel Enterprises, and will provide
power to the Pittsburg, California and greater San Francisco Bay areas. The
gas-fired power plant is to be constructed by Bechtel and operated by us.
On February 17, 1999, we announced plans to develop, own and operate a 540
megawatt gas-fired power plant in Westbrook, Maine. We acquired the development
rights for the Westbrook Power Plant from Genesis Power Corporation. This power
plant is scheduled to begin power deliveries by the end of 2000, and will serve
the New England market.
13
<PAGE>
On February 24, 1999, we announced plans to develop, own and operate a 600
megawatt gas-fired power plant located in San Jose, California. This power
plant, called the Metcalf Energy Center, is the second power plant to be
developed under the joint venture with Bechtel Enterprises, and will provide
electricity to the San Francisco Bay area.
On March 19, 1999, we completed the acquisition of Unocal Corporation's Geysers
geothermanl steam fields in northern California for approximately $102.1
million. The steam fields fuel PG&E's 12 Sonoma County power plants, totalling
544 megwatts of capacity. We purchased these plants on May 7, 1999 (see Note 12
to the Notes to Consolidated Financial Statements).
On April 14, 1999, we received approval from the California Energy Commission to
construct a 500 megawatt gas-fired power plant near Yuba City, California. This
power plant, called the Sutter Power Plant, was the first new power plant
approved in California's deregulated power industry, and is the cleanest
gas-fired power plant permitted in the United States. Electricity produced by
the Sutter Power Plant will be sold to customers under bilateral contracts and
into California's power market.
On April 22, 1999, we entered into a joint venture with GenTex Power Corporation
to develop, own and operate a 500 megawatt gas-fired power plant in Bastrop
County, Texas, called Lost Pines I. Construction of this power plant is expected
to begin in October 1999. We will manage all phases of the plant's development
process, with GenTex and ourselves jointly operating the plant. The output from
Lost Pines I will be divided equally, with GenTex selling its portion to its
customer base, while we will sell our portion to Texas' wholesale power market.
On April 23, 1999, we entered into a joint agreement with Pinnacle West Capital
Corporation to potentially develop, own and operate a 500 megawatt gas-fired
power plant located in Phoenix, Arizona. This plant, called the West Phoenix
Power Plant, will provide power to the Phoenix metropolitan area, and
construction on the facility will commence in 2001.
On May 7, 1999, we completed the acquisitions from PG&E, of 12 Sonoma County and
2 Lake County power plants for approximately $212.8 million. Our geothermal
steam fields fuel the facilities, which have a combined capacity of
approximately 700 megawatts of electricity. All of the generation from the
facilities is sold to the California energy market, with the exception of an
agreement entered into on April 29, 1999, to sell to Commonwealth Energy
Corporation 75 megawatts of geothermal electricity in 1999, 100 megawatts in
2000, and 125 megawatts in 2001 and through June 2002. Historically, we have
served as a steam supplier for these facilities, which have been owned and
operated by PG&E. These acquisitions will enable us to consolidate our
operations in The Geysers into a single ownership structure and to integrate the
power plant and steam field operations, allowing us to optimize the efficiency
and performance of the facilities. We believe that these acquisitions provide us
with significant synergies that leverage our expertise in geothermal power
generation and position us to benefit from the demand for "green" energy in the
competitive market
Selected Operating Information
Set forth below is certain selected operating information for the power plants
and steam fields, for which results are consolidated in our consolidated
statements of operations. The information set forth under power plants consists
of the results for the West Ford Flat Power Plant, Bear Canyon Power Plant,
Greenleaf 1 & 2 Power Plants, Watsonville Power Plant, King City Power Plant,
Gilroy Power Plant, the Bethpage Power Plant since its acquisition on February
5, 1998, the Texas City and Clear Lake Power Plants since their acquisition on
March 31, 1998, the Pasadena Power Plant since it began commercial operation on
July 7, 1998, the Sonoma Power Plant since its acquisition on July 17, 1998 and
the Pittsburg Power Plant since its acquisition on July 21, 1998. The
information set forth under steam fields consists of the results for the PG&E
Unit 13 and Unit 16 Steam Fields, the Sonoma Steam Fields and the Thermal Power
Company Steam Fields.
14
<PAGE>
<TABLE>
<CAPTION>
Three Months Ended
March 31,
-----------------------
(dollars in thousands) 1999 1998
---------- ----------
<S> <C> <C>
Power Plants:
Electricity revenue:
Energy .............................. $ 73,425 $ 23,314
Capacity ............................ $ 43,876 $ 9,462
Megawatt hours produced .............. 2,373,872 334,052
Average energy price per kilowatt hour 0.0309 0.0698
Steam Fields:
Steam revenue ......................... $ 10,725 $ 10,614
Megawatt hours produced .............. 691,768 641,833
Average price per kilowatt hour ...... 0.0155 0.0165
</TABLE>
Megawatt hours produced at the power plants increased 611% for the three months
ended March 31, 1999 as compared with the same period in 1998, primarily due to
1,833,697 megawatt hours of production at the Pittsburg, Pasadena, Clear Lake,
Texas City and Bethpage Power Plants.
OTHER FINANCIAL DATA 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
March 31,
------------------
1999 1998
-------- -------
<S> <C> <C>
Depreciation and amortization .......... $19,455 $12,582
Interest expense per indenture ......... $23,103 $19,724
EBITDA ................................. $51,138 $25,681
EBITDA to interest expense per indenture 2.21x 1.30x
</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 income from unconsolidated investments in power
projects. EBITDA is presented not as a measure of operating results, but rather
as a measure of our ability to service debt. EBITDA should not be construed as
an alternative either (i) to income from operations (determined in accordance
with generally accepted accounting principles) or (ii) to cash flows from
operating activities (determined in accordance with generally accepted
accounting principles).
Interest expense per indenture is defined as total interest expense plus
one-third of all operating lease obligations, dividends paid in respect to
preferred stock and cash contributions to any employee stock ownership plan used
to pay interest on loans to purchase capital stock of the company.
15
<PAGE>
Results of Operations
Three Months Ended March 31, 1999 Compared to Three Months Ended March 31, 1998
<TABLE>
<CAPTION>
Consolidated Operations
(dollars in thousands)
Three Months Ended March 31,
---------------------------------
Revenue: 1999 1998 % Change
-------- -------- --------
<S> <C> <C> <C>
Electricity and steam sales ............. $128,026 $ 43,390 195
Service contract revenue ................ 6,772 5,481 24
Income from unconsolidated investments in
power projects ....................... 10,812 3,754 188
Interest on loans to power projects ..... 303 2,520 (88)
------- --------
Total revenue ........................ 145,913 55,145 165
------- --------
</TABLE>
Revenue -- Total revenue increased 165% to $145.9 million for the three months
ended March 31, 1999 compared to $55.1 million in 1998.
Electricity and steam sales revenue increased 195% to $128.0 million in 1999
compared to $43.4 million in 1998. The increase is primarily attributable to the
acquisition of the remaining interests in the Texas City, Clear Lake and
Bethpage Power Plants and the acquisition of the Pittsburg Power Plant. These
power plants accounted for $78.3 million in additional electricity revenues in
1999. The Pasadena Power Plant, which became operational in July 1998,
contributed $12.7 million in revenue during 1999. Additionally, our Gilroy Power
Plant experienced an increase of $4.8 million in 1999 compared to the same
period in 1998 due to planned shutdowns in 1998. These increases were partially
offset by a decrease of $11.1 million at The Geysers related to the expiration
of the fixed priced period of their power sales agreements. Concurrently, the
price of electricity for two of our power plants, Bear Canyon and West Ford
Flat, was significantly reduced compared to the price for the same period in
1998.
Service contract revenue increased to $6.8 million in 1999 compared to $5.5
million in 1998. The 24% increase was primarily attributable to a $437,000
increase in third party excess gas sales, as well as an increase of $478,000 for
fuel management fees.
Income from unconsolidated investments in power projects increased 188% to
$10.8 million in 1999 compared to $3.8 million during 1998. The increase is
primarily attributable to $1.2 million of equity income from our investment in
the Bayonne Power Plant which was acquired in March 1998, an increase of $7.3
million from our Sumas equity investments and an increase of $1.2 million from
our Kennedy International Airport and Stonybrook Power Plants. These increases
were partially offset by a reduction of $2.9 million in equity income from our
Texas City and Clear Lake Power Plants, which were consolidated on March 31,
1998.
Interest income on loans to power projects decreased 88% to $303,000 in
1999 compared to $2.5 million in 1998. The decrease is primarily related to the
acquisition of the remaining 50% interest in TCC on March 31, 1998.
Cost of revenue -- Cost of revenue increased 178% to $109.5 million in 1999
compared to $39.4 million in 1998. The increase of $70.1 million was primarily
attributable to increase plant operating, fuel and depreciation expenses as a
result of the acquisition of the remaining interests in the Texas City, Clear
Lake and Bethpage Power Plants, the acquisition of the Pittsburg Power Plant and
the startup of the Pasadena Power Plant.
General and administrative expenses -- General and administrative expenses
increased 92% to $10.0 million for the three months in 1999 compared to $5.2
million in 1998. The increase was attributable to continued growth in personnel
and associated overhead costs necessary to support the overall growth in our
operations.
16
<PAGE>
Interest expense -- Interest expense increased 14% to $21.0 million for the
three months ended March 31, 1999 from $18.5 million for the same period in
1998. The increase was primarily attributable to $7.9 million of interest
associated with the issuance of senior notes in 1998, partially offset by an
increase in capitalized interest of $1.8 million, and a reduction in interest of
$2.1 million related to the acquisition of the remaining 50% interest TCC on
March 31, 1998.
Provision for income taxes -- The effective income tax rate was approximately
39% for the three months ended March 31, 1999. The reductions from the statutory
tax rate were primarily due to depletion in excess of tax basis benefits at our
geothermal facilities, and a decrease in the California taxes paid due to our
expansion into states other than California.
Liquidity and Capital Resources
To date, we have obtained cash from our operations, borrowings under our credit
facilities and other working capital lines, sale of debt and equity, and
proceeds from non-recourse project financing. We utilized this cash to fund our
operations, service debt obligations, fund the acquisition, develop and
construct power generation facilities, finance capital expenditures and meet our
other cash and liquidity needs. The following table summarizes our cash flow
activities for the periods indicated:
Three Months Ended
March 31,
----------------------
1999 1998
--------- ---------
(in thousands)
Cash flows from:
Operating activities $ 33,379 $ 3,545
Investing activities (248,600) (154,256)
Financing activities 817,646 199,158
--------- ---------
Total ...... $ 602,425 $ 48,447
========= =========
Operating activities for 1999 provided $33.4 million, consisting of
approximately $19.4 million of depreciation and amortization, $3.9 million of
net income, $10.3 million of distributions from unconsolidated investments in
power projects, $2.3 million of deferred income taxes, $7.6 million net decrease
in operating assets, and a $826,000 net increase in operating liabilities. This
was offset by $10.8 million of income from unconsolidated investments.
Investing activities for 1999 used $248.6 million, primarily due to $102.1
million for the acquisition of Unocal, $14.8 million for the acquisition of the
Sheridan Power Plant, a $6.8 million increase in restricted cash, $48.9 million
of capital expenditures related to the construction of the Pasadena Power Plant
Expansion, $55.6 million of other capital expenditures principally for turbine
purchases and for the Clear Lake Expansion project, $13.8 million of capitalized
project development costs, $3.8 million of interest capitalized on construction
projects, $4.7 million of additional loans, offset by $1.9 million of maturities
of collateral securities in connection with the King City Power Plant.
Financing activities for 1999 provided $817.6 million of cash consisting of
$47.6 million of borrowings for the construction of the Pasadena Power Plant,
$128.6 million of borrowings of non-recourse project financing, $767.5 million
of net proceeds from additional equity and senior debt financings, and $1.6
million for the issuance of common stock for our Employee Stock Purchase Plan,
partially offset by $127.6 million in repayment of non-recourse project
financing.
At March 31, 1999, cash and cash equivalents were $699.0 million and
working capital was $678.0 million. For 1999, cash and cash equivalents
increased by $602.4 million and working capital increased by $591.1 million as
compared to December 31, 1998.
As a developer, owner and operator of power generation facilities, we are
required to make long-term commitments and investments of substantial capital
for our projects. We historically have financed these capital requirements with
cash from operations, borrowings under our credit facilities, other lines of
credit, non-recourse project financing or long-term debt, and the sale of
equity.
17
<PAGE>
We continue to evaluate current and forecasted cash flow as a basis for
financing operating requirements and capital expenditures. We believe that we
will have sufficient liquidity from cash flow from operations, borrowings
available under the lines of credit and working capital to satisfy all
obligations under outstanding indebtedness, to finance anticipated capital
expenditures and to fund working capital requirements for the next twelve
months.
On January 4, 1999, we entered into a Credit Agreement with ING (U.S.)
Capital LLC to provide up to $265 million of non-recourse project financing for
the construction of the Pasadena facility expansion. As of March 31, 1999, $47.6
million was outstanding under the agreement. The outstanding loan bears interest
at ING's base rate or at LIBOR plus an applicable margin and is payable
quarterly. The loan matures on March 31, 2009. In connection with the Credit
Agreement, we entered into a $10.0 million letter of credit facility. At March
31, 1999, there were no letters of credit outstanding under the facility.
On March 26, 1999, we completed a public offering of 6,000,000 shares of our
common stock at $31.00 per share. The net proceeds from this public offering are
estimated to be approximately $177.9 million. Additionally, in April 1999, we
sold an additional 900,000 shares of common stock at $31.00 per share pursuant
to the exercise of the underwriters' over-allotment option for net proceeds of
approximately $26.7 million.
On March 29, 1999, we completed a public offering of $250 million of our
7-5/8% Senior Notes Due 2006 and of our $350 million 7-3/4% Senior Notes Due
2009. After deducting underwriting discounts and expenses of the offering, the
aggregate net proceeds from the sale of the Senior Notes were approximately
$589.6 million. The Senior Notes due 2006 bear interest at 7-5/8% per year,
payable semi-annually on April 15 and October 15 each year and mature on April
15, 2006. The Senior Notes due 2006 are not redeemable prior to maturity. The
Senior Notes due 2009 bear interest at 7-3/4% per year, payable semi-annually on
April 15 and October 15 each year and mature on April 15, 2009. The Senior Notes
due 2009 are not redeemable prior to maturity.
The net proceeds from the sale of common stock, the Senior Notes Due 2006,
and the Senior Notes Due 2009 will be used as follows: (i) $119.6 million to
refinance indebtedness relating to the Gilroy Power Plant, (ii) $77.6 million to
repay indebtedness under a bridge facility provided by Credit Suisse First
Boston to finance a portion of the purchase price to acquire the steam fields
that service the Sonoma Power Plants, (iii) $50.0 million to repay outstanding
borrowings under our revolving credit facility, $23.4 million of which was
incurred to finance a portion of the steam fields that service the Sonoma Power
Plants, (iv) $25.0 million to complete the expansion of the Clear Lake Power
Plant, and (v) approximately $400.0 million to finance a portion of power
generation facilities currently under construction and the projects currently
under development. Transaction costs incurred in connection with the Senior Note
offering were recorded as a deferred charge and are amortized over the
respective lives of the Senior Notes Due 2006 and the Senior Notes Due 2009
using the effective interest rate method.
At March 31, 1999, we also had $105.0 million of outstanding 9-1/4% Senior
Notes Due 2004, which mature on February 1, 2004, with interest payable
semi-annually on February 1 and August 1 of each year. In addition, we had
$171.8 million of outstanding 10-1/2% Senior Notes Due 2006, which mature on May
15, 2006, with interest payable semi-annually on May 15 and November 15 of each
year. During 1997, we issued $275.0 million of 8-3/4% Senior Notes Due 2007,
which mature on July 15, 2007, with interest payable semi-annually on January 15
and July 15 of each year. During 1998, we issued $400.0 million of 7 7/8% Senior
Notes Due 2008, which mature on April 1, 2008, with interest payable
semi-annually on April 1 and October 1 of each year.
At March 31, 1999, we had a $100.0 million revolving credit facility
available with a consortium of commercial lending institutions. We had no
borrowings and $21.9 million of letters of credit outstanding under the credit
facility (See Note 9 to the Notes to Consolidated Financial Statements). The
credit facility contains certain restrictions that limit or prohibit, among
other things, our ability to incur indebtedness, make payments of certain
indebtedness, pay dividends, make investments, engage in transactions with
affiliates, create liens, sell assets and engage in mergers and consolidations.
18
<PAGE>
At March 31, 1999, we had a $12.0 million letter of credit outstanding with
The Bank of Nova Scotia to secure performance of the Clear Lake Power Plant.
We have a $1.1 million working capital line with a commercial lender that
may be used to fund short-term working capital commitments and letters of
credit. At March 31, 1999, we had no borrowings under this working capital line
and $74,000 of letters of credit outstanding. Borrowings accrue interest at
prime plus 1%.
Outlook
Our strategy is to continue our rapid growth by capitalizing on the significant
opportunities in the power market, primarily through our active development and
acquisition programs. In pursuing our proven growth strategy, we utilize our
extensive management and technical expertise to implement a fully integrated
approach to the acquisition, development and operation of power generation
facilities. This approach uses our expertise in design, engineering,
procurement, finance, construction management, fuel and resource acquisition,
operations and power marketing, which we believe provide us with a competitive
advantage. The key elements of our strategy are as follows:
- -- Development and expansion of power plants. We are actively pursuing the
development and expansion of highly efficient, low-cost, gas-fired power
plants that replace old and inefficient generating facilities and meet the
demand for new generation. Our strategy is to develop power plants in
strategic geographic locations that enable us to leverage existing power
generation assets and operate the power plants as integrated electric
generation systems. This allows us to achieve significant operating
synergies and efficiencies in fuel procurement, power marketing and
operations and maintenance.
- -- We currently have six new projects under construction, representing an
additional 1,784 megawatts of capacity. Of these new projects, we are
expanding our Pasadena and Clear Lake facilities by an aggregate of 545
megawatts. In addition, four new gas-fired power plants, which will produce
an estimated 1,239 megawatts of electricity, are currently under
construction in Dighton, Massachusetts; Tiverton, Rhode Island; Rumford,
Maine; and Westbrook, Maine. We have also announced plans to develop five
additional power generation facilities, totaling an estimated 3,180
megawatts of electricity, in California, Texas, Arizona and Maine.
- -- Acquisition of power plants. Our strategy is to acquire power generating
facilities that meet our stringent acquisition criteria and that provide
significant potential for revenue, cash flow and earnings growth and that
provide the opportunity to enhance the operating efficiencies of the
plants. We have significantly expanded and diversified our project
portfolio through the acquisition of power generation facilities through
the completion of 23 acquisitions to date.
- -- We completed two acquisitions subsequent to the March 31, 1999 Consolidated
Financial Statements (See Note 12 to the Notes to Consolidated Financial
Statements), comprising of 14 geothermal power plants with an aggregate
capacity of 694 megawatts and certain related steam fields located in The
Geysers, California. Historically, we have served as a steam supplier for
these facilities, which have been owned and operated by PG&E. These
acquisitions will enable us to consolidate our operations in The Geysers
into a single ownership structure and to integrate the power plant and
steam field operations, allowing us to optimize the efficiency and
performance of the facilities. We believe that these acquisitions provide
us with significant synergies that leverage our expertise in geothermal
power generation and position us to benefit from the demand for "green"
energy in the competitive market.
- -- Enhance the performance and efficiency of existing power projects. We
continually seek to maximize the power generation potential of our
operating assets and minimize our operating and maintenance expenses and
fuel costs. This will become even more significant as our portfolio of
power generation facilities expands to an aggregate of 40 power plants with
an aggregate capacity of 5,207 megawatts, after completion of our pending
acquisitions and projects currently under construction. We focus on
operating our plants as an integrated system of power generation, which
enables us to minimize costs and maximize operating efficiencies. We
believe that achieving and maintaining a low-cost of production will be
increasingly important to compete effectively in the power generation
market.
19
<PAGE>
Deregulation within the Power Generation Industry. Many states are
implementing or considering regulatory initiatives designed to increase
competition in the domestic power generation industry. In December 1995, the
California Public Utilities Commission ("CPUC") issued an electric industry
restructuring decision, which envisioned commencement of deregulation and
implementation of customer choice of electricity supplier by January 1, 1998.
Legislation implementing this decision was adopted in September 1996. The CPUC
subsequently extended the implementation date to April 1, 1998. 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
operations. The Company believes that any such restructuring would not have a
material effect on all of 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.
Financial Market Risks
From time to time, we use interest rate swap agreements to mitigate our exposure
to interest rate fluctuations. We do not use derivative financial instruments
for speculative or trading purposes. The following table summarizes the fair
market value of our existing interest rate swap agreements as of March 31, 1999
(in thousands):
Notional Weighted
Principal Average Fair Market
Maturity Date Amount Interest Rate Value
- -------------- --------- ------------- -----------
2000 $ 28,000 9.9% $ (869)
2006 10,000 7.1% (757)
2009 65,000 6.1% (1,466)
2011 17,600 6.8% (896)
2013 75,000 7.2% (6,559)
2014 52,370 6.5% (2,075)
--------- -----------
Total $247,970 7.0% $(12,622)
========= ===========
Short-term investments. As of March 31, 1999, we have short-term investments of
$4.2 million. These short-term investments consist of highly liquid investments
with maturities between three and twelve months. These investments are subject
to interest rate risk and will increase in value if market interest rates
increase. We have the ability to hold these investments to maturity, and as a
result, we would not expect the value of these investments to be affected to any
significant degree by the effect of a sudden change in market interest rates.
Declines in interest rates over time will reduce our interest income.
Outstanding debt. As of March 31 1999, we have outstanding long-term debt
of approximately $1.7 billion primarily made up of $1.6 billion of senior notes
and $120.6 million of non-recourse project financing. Our non-recourse project
financing is stated at fair market value and bears a weighted average interest
rate of 6.8%. Our outstanding long-term Senior Notes as of March 31, 1999 are as
follows (in thousands):
Carrying Fair Market
Maturity Date Amount Interest Rate Value
- ------------- ---------- ------------- ----------
2004 $ 105,000 9-1/4% $ 108,200
2006 171,750 10-1/2% 188,900
2006 250,000 7-5/8% 250,000
2007 275,000 8-3/4% 288,800
2008 400,000 7-7/8% 403,000
2009 350,000 7-3/4% 350,000
---------- ----------
Total $ 1,551,750 $1,588,900
=========== ==========
20
<PAGE>
Gas prices fluctuations. We enter into derivative commodity instruments to
hedge our exposure to the impact of price fluctuations on gas purchases. Such
instruments include regulated natural gas contracts and over-the-counter swaps
and basis hedges with major energy derivative product specialists. All hedge
transactions are subject to our risk management policy which does not permit
speculative positions. These transactions are accounted for under the hedge
method of accounting. Cash flows from derivative instruments are recognized as
incurred through changes in working capital.
We use a sensitivity analysis to evaluate the hypothetical effect that
changes in the market value of natural gas may have on the fair value of our
derivative instruments. This analysis measures the impact on the commodity
derivative instruments and, thereby, does not consider the underlying exposure
related to the commodity. However, gains and losses on derivative contracts are
expected to be similarly offset by sales at the spot market price. Due to the
short duration of the contracts, time value of money is ignored. The
hypothetical change in fair value is calculated by multiplying the difference
between the hypothetical price and the contractual price by the contractual
volumes.
Impact of Recent Accounting Pronouncements -- In June 1997, the Financial
Accounting Standards Board ("FASB") issued Statement of Financial Accounting
Standards ("SFAS") No. 131, "Disclosures about Segments of an Enterprise and
Related Information." This Statement establishes the reporting of information
about operating segments in annual financial statements and requires that
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. During 1998, we started the process of decentralization of our
operations and completed this process during the first quarter of calendar 1999.
We have adopted this pronouncement beginning January 1999 (see Note 5 of the
Notes to Consolidated Financial Statements).
In June 1998, FASB also issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". This Statement establishes accounting and
reporting standards, requiring every derivative instrument be recorded in the
balance sheet as either an asset or liability measured at its fair value. This
Statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and require
that a company formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999.
This Statement must be applied to derivative instruments and to certain
derivative instruments embedded in hybrid contracts that were issued, acquired,
or substantively modified after December 31, 1997. We have not yet analyzed the
impact of adopting SFAS No. 133 on the financial statements and have not
determined the timing of or method of the adoption of SFAS No. 133. However,
this Statement could increase volatility in earnings.
Year 2000 Compliance. -- The "Year 2000 problem" refers to the fact that some
computer hardware, software and embedded systems were designed to read and store
dates using only the last two digits of the year.
We are coordinating our efforts to address the impact of Year 2000 on our
business through a Year 2000 Project Team comprised of representatives from each
business unit and our Year 2000 Project Office. The Year 2000 Project Office is
charged with addressing additional Year 2000 related issues including, but not
limited to, business continuation and other contingency planning. The Year 2000
Project Team meets regularly to monitor the efforts of assigned staff and
contractors to identify, remediate and test our technology.
The Year 2000 Project Team is focusing on four separate technology domains:
21
<PAGE>
- -- Corporate applications, which include core business systems;
- -- Non-Information technology, which includes all operating and control
systems;
- -- End-User computing systems (that is, systems that are not, considered core
business systems but may contain date calculations); and
- -- Business partner and vendor systems.
Corporate Applications - Corporate applications are those major core
systems, such as customer information, human resources and general ledger, for
which our Management Information Systems department has the responsibility. We
utilize PeopleSoft for our major core systems. The PeopleSoft applications are
in operation and have been determined to be Year 2000 compliant.
Non-Information Technology/Embedded Systems - Non-information technology
includes such items as power plant operating and control systems,
telecommunications and facilities-based equipment (e.g. telephones and two-way
radios) and other embedded systems. Each business unit is responsible for the
inventory and remediation of its embedded systems. In addition, we are working
with the Electric Power Research Institute, a consortium of power companies,
including investor-owned utilities, to coordinate vendor contacts and product
evaluation. Because many embedded systems are similar across utilities, this
concentrated effort should help to reduce total time expended in this area and
help to ensure that the Company's efforts are consistent with the efforts and
practices of other power companies and utilities.
An Inventory phase for non-information technology/embedded systems was completed
in October 1998. The Initial Assessment Phase was completed in December 1998. We
plan to complete remediation of non-compliant systems by the second quarter of
1999. To date, all embedded systems that have been identified by Calpine can be
upgraded or modified within our current schedule. The schedule for addressing
year 2000 issues with respect to mission critical embedded systems is as
follows:
PHASE STATUS ESTIMATED COMPLETION DATE
- ------------------------------------------------------------------------
Inventory Complete September 1998
Initial Assessment Complete November 1998
Detail Assessment In-progress (92%) February 1999 - May 1999
Remediation In-progress (70%) May 1999 - June 1999
Contingency Planning In-progress (5%) June 1999 - Oct 1999
Testing of embedded systems is complex because some of the testing must be
completed during power plant scheduled maintenance outages. Much of the testing
will be accomplished in the spring of 1999 during regularly scheduled
maintenance outage periods. At that time, at least one typical unit of each
critical type will be tested by Calpine or in cooperation with other power
companies, and the requirement for further testing will be determined.
End-User Computing Systems - Some of our business units have developed
systems, databases, spreadsheets, etc. that contain date calculations.
Compliance of individual workstations is also included in this domain. These
systems comprise a relatively small percentage of the required modification in
terms of both number and criticality.
Our end-user computing systems are being inventoried by each business unit
and evaluated and remediated by the Company's MIS staff. We expect to complete
remediation and testing of the end-user computing systems by mid-1999.
-- Business Partner and Vendor Systems -- We have contracts with business
partners and vendors who provide products and services to the Company.
We are vigorously seeking to obtain Year 2000 assurances from these
third parties. Year 2000 Project Team and appropriate business units
are jointly undertaking this effort. We have sent letters and
accompanying Year 2000 surveys to about 800 vendors and suppliers.
Over 600 responses have been received as of March 31 1999. These
responses outline to varying degrees the approaches vendors are
undertaking to resolve Year 2000 issues within their own systems.
Follow-up letters are being sent to those vendors who have not
responded or whose responses were inadequate.
22
<PAGE>
Contingency Planning - Contingency and business continuation planning are
in various stages of development for critical and high-priority systems. Our
existing disaster response plan and other contingency plans are scheduled to be
evaluated and will be adopted for use in case of any Year 2000-related
disruption. We expect to complete our contingency planning by October 1999.
Costs - The costs of expected modifications are currently estimated to be
approximately $1.7 million which will be charged to expense as incurred. From
January 1, 1998 through March 31, 1999, $158,000 has been charged to expense.
Approximately 12% of the estimated total cost has been incurred in 1998, 63%
will be incurred in 1999, and the remainder will be incurred in 2000. These
costs have been and will be funded through operating cash flow. These estimates
may change as additional evaluations are completed and remediation and testing
progress.
Risks - We currently expect to complete our Year 2000 efforts with respect
to critical systems by mid-1999. This schedule and our cost estimates may be
affected by, among other things, the availability of Year 2000 personnel, the
readiness of third parties, the timing for testing our embedded systems, the
availability of vendor resources to complete embedded system assessments and
produce required component upgrades and our ability to implement appropriate
contingency plans.
We produce revenues by selling power we produce to customers. We depend on
transmission and distribution facilities that are owned and operated by
investor-owned utilities to deliver power to the our customers. If either our
customers or the providers of transmission and distribution facilities
experience significant disruptions as a result of the Year 2000 problem, our
ability to sell and deliver power may be hindered, which could result in a loss
of revenue.
The cost or consequences of a materially incomplete or untimely resolution
of the Year 2000 problem could adversely affect our future operations, financial
results or our financial condition.
The forward-looking statements discussed in this outlook section involve a
number of risks and uncertainties. Other risks and uncertainties include, but
are not limited to, the general economy, regulatory conditions, the changing
environment of the power generation industry, pricing, the effects of legal and
administrative cases and proceedings, and such other risks and uncertainties as
may be detailed from time to time in our SEC reports and filings.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund
("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and
certain other parties, including the Company. Some of Indeck's claims relate to
Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville
Energy L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s
acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck claimed that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. In April 1999, the court granted Calpine Gordonsville
and Calpine Auburndale's motions to dismiss with prejudice. The Company is
unable to predict the outcome of these proceedings.
There is currently a dispute between Texas-New Mexico Power Company ("TNP") and
Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear Lake
Power Plant, regarding certain costs and other amounts that TNP has withheld
from payments due under the power sales agreement from August 1997 until October
1998. TNP has withheld approximately $450,000 per month related
23
<PAGE>
to transmission charges. In October 1997, CLC filed a petition for declaratory
order with the Texas Public Utilities Commission ("Texas PUC") requesting a
declaration that TNP's withholding is in error, which petition is currently
pending. Also, as of March 31, 1999, TNP has withheld approximately $7.7 million
of standby power charges. In addition to the Texas PUC petition, CLC filed an
action in Texas courts on October 2, 1997, alleging TNP's breach of the power
sales agreement and is seeking refund of the standby charges. In October 1998,
TNP and CLC reached an agreement in principle to settle all outstanding
disputes. The parties are currently finalizing the documentation of the
settlement which must be approved by the Texas PUC. Both the Texas PUC action
and the court action have been put on hold pending completion of the settlement.
The Company does not believe this has a material adverse effect on the
consolidated financial statements.
An action was filed against Lockport Energy Associates, L.P. ("LEA") and the New
York Public Service Commission ("NYPSC") in August 1997 by New York State
Electricity and Gas Company ("NYSEG") in the Federal District Court for the
Northern District of New York. NYSEG has requested the Court to direct NYPSC and
the Federal Energy Regulatory Commission (the "FERC") to modify contract rates
to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a
cross-claim alleging that the FERC violated the Public Utility Regulatory
Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by failing
to reform the NYSEG contract that was previously approved by the NYPSC. Although
it is unable to predict the outcome of this case, in any event, the Company
retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase
the Company's interest in the Lockport Power Plant for $18.9 million, less
equity distributions received by the Company, at any time before December 19,
2001.
The Company is involved in various other claims and legal actions arising out of
the normal course of business. The Company does not expect that the outcome of
these proceedings will have a material adverse effect on the Company's financial
position or results of operations, although no assurance can be given in this
regard.
ITEM 2. CHANGE IN SECURITIES
None.
ITEM 3. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to Part II, Item 7A, Quantitative and Qualitative Disclosures
About Market Risk, in the Company's Annual Report on Form 10-K for the year
ended December 31, 1998 and to the subheading "Financial Market Risks" under the
heading "Management's Discussion and Analysis of Financial Condition and Results
of Operations" on pages 35-36 of the Company's Annual Report on Form 10-K for
the year ended December 31, 1998.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Reports on Form 8-K
No reports were filed on Form 8-K during the quarter ended March 31,1999.
(b) Exhibits
The following exhibits are filed herewith unless otherwise indicated:
24
<PAGE>
Exhibit
Number Description
3.1 --Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(b)
3.2 --Amended and Restated Bylaws of Calpine Corporation, a Delaware
corporation.(b)
4.1 --Indenture dated as of February 17, 1994 between the Company and
Shawmut Bank of 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.(d)
4.3 --Indenture dated as of July 8, 1997 between the Company and The Bank
of New York, as Trustee, including form of Notes.(g)
4.4 --Indenture dated as of March 31, 1998 between the Company and The
Bank of New York, as Trustee, including form of Notes.(l)
4.5 --Indenture dated as of March 26, 1999 between the Company and The
Bank of New York, as Trustee, including form of Notes.(m)
10.1 --Financing Agreements
10.1.1 --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)
10.1.2 --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)
10.1.3 --Lease dated as of April 24, 1996 between BAF Energy A California
Limited Partnership, Lessor, and Calpine King City Cogen, LLC,
Lessee.(c)
10.1.4 --Credit Agreement, dated as of August 28, 1996, among Calpine
Gilroy Cogen, L.P. and Banque Nationale de Paris.(b)
10.1.5 --Credit Agreement, dated as of September 25, 1996, among Calpine
Corporation and The Bank of Nova Scotia.(c) 10.1.6 --Credit Agreement,
dated December 20, 1996, among Pasadena Cogeneration L.P. and ING
(U.S.) Capital Corporation and The Bank Parties Hereto.(e)
10.2 --Purchase Agreements
10.2.1 --Asset Purchase Agreement, dated as of August 28, 1996, among
Gilroy Energy Company, McCormick & Company, Incorporated and Calpine
Gilroy Cogen, L.P.(d)
10.2.2 --Noncompetition/Earnings Contingency Agreement, dated as of August
28, 1996, among Gilroy Energy Company, McCormick & Company,
Incorporated and Calpine Gilroy Cogen, L.P.(d)
10.2.3 --Purchase and Sale Agreement dated March 27, 1997 for the purchase
and sale of shares of Enron/Dominion Cogen Corp. Common Stock among
Enron Power Corporation and Calpine Corporation.(i)
10.2.4 --Stock Purchase and Redemption Agreement dated March 31, 1998,
among Dominion Cogen, Inc. Dominion Energy, Inc. and Calpine
Finance.(i)
10.2.5 --Stock Purchase Agreement Among Gas Energy Inc., Gas Energy
Cogeneration Inc., Calpine Eastern Corporation and Calpine Corporation
dated August 22, 1997.(h)
10.2.6 --First Amendment to the Stock Purchase Agreement Among Gas Energy
Inc., Gas Cogeneration Inc., The Brooklyn Union Gas Company and
Calpine Eastern Corporation and Calpine Corporation dated August 22,
1997; as amended on December 19, 1997.(h)
10.2.7 --Amended and Restated Cogenerated Electricity Sale and Purchase
Agreement by and between Cogenron Inc., and Texas Utilities Electric
Company dated June 12, 1985; as previously amended, and as amended and
restated on December 29, 1997.(h)
10.2.8 --Agreement for the Purchase of Electrical Power and Energy between
Capital Cogeneration Company Ltd. And Texas-New Mexico Power Company
Agreement.(h)
10.2.9 --Stock Purchase Agreement dated May 1, 1998 and between Calpine
Corporation and CCNG Investments, L.P.(k)
25
<PAGE>
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)
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
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.(b)
10.3.6 --Amended and Restated Energy Sales Agreement, dated December 16,
1996, between Phillips Petroleum Company and Pasadena Cogeneration,
L.P.(e)
10.4 --Steam Sales Agreements
10.4.1 --Amendment to the Steam and Electricity Service Agreement between
Cogenron Inc. and Union Carbide Corporation dated June 12, 1985.(h)
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)
10.8 --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 --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)
10.8.5 --Ground Lease Agreement, between Union Carbide Corporation and
Northern Cogeneration One Company, dated January 1, 1986.(h)
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.(b)
10.9.3 --Calpine Corporation Employee Stock Purchase Plan and forms of
agreements thereunder.(b)
10.10.1 --Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright.(b)
10.10.2 --Senior Vice President Employment Agreement between Calpine
Corporation and Ms. Ann B. Curtis.(b)
10.10.3 --Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Lynn A. Kerby.(b)
10.10.4 --Vice President Employment Agreement between Calpine Corporation
and Mr. Ron A. Walter.(b)
26
<PAGE>
10.10.5 --Vice President Employment Agreement between Calpine Corporation
and Mr. Robert D. Kelly.(b)
10.10.6 --First Amended and Restated Consulting Contract between Calpine
Corporation and Mr. George J. Stathakis.(b) 10.11 --Form of
Indemnification Agreement for directors and officers.(b)
21.1 --Subsidiaries of the Company.(d)
27.0 --Financial Data Schedule.* ___________
(a) Incorporated by reference to Registrant's Registration Statement on
Form S-1 (Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Registration Statement on
Form S-1 (Registration Statement No. 333-07497).
(c) Incorporated by reference to Registrant's Current Report on Form 8-K
dated May 1, 1996 and filed on May 14, 1996.
(d) Incorporated by reference to Registrant's Current Report on Form 8-K
dated August 29, 1996 and filed on September 13, 1996.
(e) Incorporated by reference to Registrant's Annual Report on Form 10-K
dated December 31, 1996, filed on March 27, 1996.
(f) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1997 and filed on May 12, 1997.
(g) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1997 and filed on August 14, 1997.
(h) Incorporated by reference to Registrant's Annual Report on Form 10-K/A
dated December 31, 1997 and filed on April 1, 1998.
(i) Incorporated by reference to Registrant's Current Report on Form 8-K
dated March 31, 1998 and filed on April 14, 1998.
(j) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1998 and filed on April 14, 1998.
(k) Incorporated by reference to Registrant's Current Report on Form 8-K
dated May 26, 1998 and filed on June 9, 1998.
(l) Incorporated by reference to Registrant's Registration Statement on
Form S-4, filed on August 10, 1998 (Registration Statement No. 333-61047).
(m) Incorporated by reference to Registrant's Form 424B filed on March 26,
1999 with the Securities and Exchange Commission.
* Filed herewith.
Exhibit 27 Financial Data Schedule
27
<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: May 13, 1999
------------------------
Ann B. Curtis
Executive Vice President
(Chief Financial Officer)
By: /s/ Charles B. Clark Date: May 13, 1999
------------------------
Charles B. Clark, Jr.
Vice President and
Corporate Controller
(Chief Accounting Officer)
28
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CALPINE
CORPORATION'S CONSOLIDATED BALANCE SHEET AS OF MARCH 31, 1999 AND FROM THE
CONSOLIDATED STATEMENT OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 1999
AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH STATEMENTS.
</LEGEND>
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<NAME> Calpine Corporation
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<S> <C>
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<FISCAL-YEAR-END> Dec-31-1999
<PERIOD-START> Jan-01-1999
<PERIOD-END> Mar-31-1999
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