<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 June 30, 1999
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 for the transition period from ______________________
to ______________________
Commission File Number: 033-73160
CALPINE CORPORATION
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date: $0.001 par value Common Stock
27,174,147 shares outstanding on August 2, 1999.
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q
For the Three and Six Months Ended June 30, 1999
INDEX
PART I. FINANCIAL INFORMATION Page No.
ITEM 1. Financial Statements
Consolidated Balance Sheets
June 30, 1999 and December 31, 1998 ............................... 3
Consolidated Statements of Operations
Three and Six Months Ended June 30, 1999 and 1998 ................. 4
Consolidated Statements of Cash Flows
Six Months Ended June 30, 1999 and 1998 ........................... 5
Notes to Consolidated Financial Statements ........................ 6
ITEM 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations ...................... 15
PART II..OTHER INFORMATION
ITEM 1. Legal Proceedings ........................................ 29
ITEM 2. Change in Securities ..................................... 30
ITEM 3. Quantitative and Qualitative Disclosures
about Market Risk......................................... 30
ITEM 4. Submission of Matters to a Vote of Security Holders ...... 30
ITEM 5. Other Information ........................................ 30
ITEM 6. Exhibits and Reports on Form 8-K ......................... 30
Signatures ................................................................. 33
2
<PAGE>
ITEM 1. FINANCIAL STATEMENTS
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, 1999 and December 31, 1998
(in thousands)
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
---------- ------------
(unaudited)
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents ............................ $ 320,287 $ 96,532
Accounts receivable from related parties ............. 1,745 4,115
Accounts receivable .................................. 116,845 79,743
Inventories .......................................... 14,504 14,194
Other current assets ................................. 20,428 14,919
---------- ----------
Total current assets ......................... 473,809 209,503
---------- ----------
Property, plant and equipment, net ..................... 1,568,882 1,094,303
Investments in power projects .......................... 234,584 221,509
Project development costs .............................. 49,563 17,001
Collateral securities, net of current portion .......... 84,818 86,920
Notes receivable from related parties .................. 16,202 10,899
Restricted cash ........................................ 38,719 14,454
Deferred financing costs ............................... 30,091 22,789
Other assets ........................................... 53,082 51,568
---------- ----------
Total assets ................................. $2,549,750 $1,728,946
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Non-recourse project financing, current portion ...... $ -- $ 5,450
Accounts payable ..................................... 44,070 53,190
Accrued interest payable ............................. 37,623 25,600
Other current liabilities ............................ 45,687 38,339
---------- ----------
Total current liabilities .................... 127,380 122,579
---------- ----------
Construction financing ................................. 79,210 --
Non-recourse project financing, net of current portion.. -- 114,190
Senior notes ........................................... 1,551,750 951,750
Deferred income taxes, net ............................. 173,072 159,788
Deferred lease incentive ............................... 66,029 67,814
Other liabilities ...................................... 38,182 25,859
---------- ----------
Total liabilities ............................ 2,035,623 1,441,980
---------- ----------
Stockholders' equity:
Preferred stock, $0.001 par value per share:
authorized 10,000,000 shares, none issued
and outstanding in 1999 and 1998 .................... -- --
Common stock, $0.001 par value per share:
authorized 100,000,000 shares; issued and
outstanding 27,174,147 in 1999 and
20,161,581 in 1998 .................................. 27 20
Additional paid-in capital ........................... 374,618 168,874
Retained earnings .................................... 139,482 118,072
---------- ----------
Total stockholders' equity ................... 514,127 286,966
---------- ----------
Total liabilities and stockholders' equity ... $2,549,750 $1,728,946
========== ==========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
3
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
For the Three and Six Months Ended June 30, 1999 and 1998
(in thousands, except per share amounts)
(unaudited)
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Revenue:
Electricity and steam sales ....... $ 176,296 $ 135,408 $ 304,322 $ 178,798
Service contract revenue .......... 6,466 3,048 13,238 8,529
Income from unconsolidated
investments in power projects .... 7,509 3,099 18,321 6,853
Interest income on loans
to power projects ................ 406 42 709 2,562
--------- --------- --------- ---------
Total revenue ............... 190,677 141,597 336,590 196,742
--------- --------- --------- ---------
Cost of revenue:
Plant operating expenses .......... 26,648 18,565 49,784 28,837
Fuel expense ...................... 61,521 52,164 115,458 57,835
Depreciation ...................... 23,310 18,461 42,289 30,811
Production royalties .............. 3,209 2,366 5,626 5,238
Operating lease expenses .......... 7,959 3,308 13,552 6,616
Service contract expenses ......... 6,016 1,892 11,461 6,788
--------- --------- --------- ---------
Total cost of revenue ...... 128,663 96,756 238,170 136,125
--------- --------- --------- ---------
Gross profit ....................... 62,014 44,841 98,420 60,617
Project development expenses ....... 2,292 1,438 4,248 3,119
General & administrative expenses .. 10,933 5,807 20,964 11,043
--------- --------- --------- ---------
Income from operations ........ 48,789 37,596 73,208 46,455
Other expense (income):
Interest expense .................. 26,144 22,267 47,171 40,790
Interest income ................... (7,054) (3,332) (9,832) (5,695)
Other income, net ................. (1,073) (503) (1,236) (904)
--------- --------- --------- ---------
Income before provision
for income taxes ............... 30,772 19,164 37,105 12,264
Provision for income taxes ......... 12,062 7,236 14,545 3,393
--------- --------- --------- ---------
Income before extraordinary charge 18,710 11,928 22,560 8,871
Extraordinary charge, net of tax
benefit of $793 and $207 ......... 1,150 302 1,150 302
--------- --------- --------- ---------
Net income .................... $ 17,560 $ 11,626 $ 21,410 $ 8,569
========= ========= ========= =========
Basic earnings per common share:
Weighted average shares outstanding 26,923 20,105 23,759 20,056
Income before extraordinary charge $ 0.69 $ 0.59 $ 0.95 $ 0.44
Extraordinary charge .............. $ (0.04) $ (0.01) $ (0.05) $ (0.01)
Net income ........................ $ 0.65 $ 0.58 $ 0.90 $ 0.43
Diluted earnings per common share:
Weighted average shares outstanding 28,524 21,126 25,235 21,050
Income before extraordinary charge $ 0.66 $ 0.56 $ 0.89 $ 0.42
Extraordinary charge .............. $ (0.04) $ (0.01) $ (0.04) $ (0.01)
Net income ........................ $ 0.62 $ 0.55 $ 0.85 $ 0.41
</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 Six Months Ended June 30, 1999 and 1998
(in thousands)
(unaudited)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
----------------------
1999 1998
--------- ---------
<S> <C> <C>
Cash flows from operating activities:
Net income ...................................... $ 21,410 $ 8,569
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization .................. 44,086 31,428
Deferred income taxes, net ..................... 13,285 2,374
Income from unconsolidated investments
in power projects ............................. (18,321) (6,853)
Distributions from unconsolidated power projects 25,522 12,995
Change in operating assets and liabilities:
Accounts receivable .......................... (34,503) (6,486)
Inventories ................................. 440 327
Other current assets ......................... 3,258 6,961
Other assets ................................. (3,794) (5,967)
Accounts payable and accrued expenses ........ 10,037 (23,245)
Other liabilities ............................ (2,865) 2,970
--------- ---------
Net cash provided by operating activities .. 58,555 23,073
--------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment .... (423,874) (23,983)
Acquisitions .................................... (117,824) (160,517)
Proceeds from sale and leaseback of plant ....... 18,436 --
Decrease (increase) in notes receivable ......... (5,303) 13,814
Maturities of collateral securities ............. 1,850 6,030
Project development costs ....................... (47,837) (10,076)
Proceeds from restricted cash ................... (15,776) (191)
--------- ---------
Net cash used in investing activities ....... (590,328) (174,923)
--------- ---------
Cash flows from financing activities:
Borrowings from construction financing .......... 79,210 --
Borrowings from non-recourse project financing .. 128,585 54,974
Repayments of non-recourse project financing .... (248,225) (141,085)
Proceeds from issuance of Senior Notes .......... 600,000 296,000
Proceeds from equity offering ................... 204,585 --
Proceeds from issuance of common stock .......... 1,167 427
Write-off of deferred financing costs ........... 1,943 --
Financing costs ................................. (11,737) (6,620)
--------- ---------
Net cash provided by financing activities ... 755,528 203,696
--------- ---------
Net increase in cash and cash equivalents ......... 223,755 51,846
Cash and cash equivalents, beginning of period .... 96,532 48,513
--------- ---------
Cash and cash equivalents, end of period .......... $ 320,287 $ 100,359
========= =========
Cash paid during the period for:
Interest ........................................ $ 42,088 $ 36,121
Income taxes .................................... $ 1,471 $ 188
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
5
<PAGE>
CALPINE CORPORATION AND SUBIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
1. Organization and Operation of the Company
Calpine Corporation, a Delaware corporation, and subsidiaries (collectively, the
"Company") is engaged in the development, acquisition, ownership, and operation
of power generation facilities and the sale of electricity and steam principally
in the United States. The Company has ownership interests in and operates
gas-fired cogeneration facilities, geothermal steam fields and geothermal power
generation facilities in northern California, Washington, Texas and various
locations on the East Coast. Each of the generation facilities produces
electricity which is marketed to utilities and other third party purchasers.
Thermal energy produced by the gas-fired cogeneration facilities is primarily
sold to industrial users.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying interim consolidated financial
statements of the Company have been prepared by the Company, without audit by
independent public accountants, pursuant to the rules and regulations of the
Securities and Exchange Commission. In the opinion of management, the
consolidated financial statements include the adjustments necessary to present
fairly the information required to be set forth therein. Certain information and
note disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles have been condensed or
omitted from these statements pursuant to such rules and regulations and,
accordingly, should be read in conjunction with the audited consolidated
financial statements of the Company included in the Company's annual report on
Form 10-K for the year ended December 31, 1998. The results for interim periods
are not necessarily indicative of the results for the entire year.
Capitalized interest -- The Company capitalizes interest on projects during the
construction period. For the six months ended June 30, 1999 and 1998, the
Company capitalized $14.0 million and $3.7 million, respectively, of interest in
connection with the construction of power plants.
Derivative financial instruments -- The Company engages in activities to manage
risks associated with changes in interest rates. The Company has entered into
swap agreements to reduce exposure to interest rate fluctuations in connection
with certain debt commitments. The instruments' cash flows mirror those of the
underlying exposures. Unrealized gains and losses relating to the instruments
are being deferred over the lives of the contracts. The premiums paid on the
instruments, as measured at inception, are being amortized over their respective
lives as components of interest expense. Any gains or losses realized upon the
early termination of these instruments are deferred and recognized in income
over the remaining life of the underlying debt.
New Accounting Pronouncements -- In May 1999, the FASB issued an Exposure Draft
entitled - "Deferral of the Effective Date of FASB Statement No. 133." The
Exposure Draft would amend SFAS. No. 133 to defer its effective date to all
fiscal quarters of all fiscal years beginning after June 15, 2000. The Company
has not yet analyzed the impact of adopting SFAS No. 133 on the financial
statements and has not determined the timing of or method of the adoption of
SFAS No. 133. However, this Statement could increase volatility in earnings.
Reclassifications -- Prior period amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1999
presentation.
6
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1999
3. Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
June 30, December 31,
1999 1998
----------- -----------
Geothermal properties ........................ $ 406,893 $ 312,139
Buildings, machinery and equipment ........... 669,443 653,865
Power sales agreements ....................... 145,975 145,957
Gas contracts ................................ 122,543 122,561
Other assets ................................. 32,802 18,955
----------- -----------
1,377,656 1,253,477
Less accumulated depreciation and amortization (231,605) (203,984)
----------- -----------
1,146,051 1,049,493
Land ......................................... 1,590 1,590
Construction in progress ..................... 421,241 43,220
----------- -----------
Property, plant and equipment, net ........... $ 1,568,882 $ 1,094,303
=========== ===========
Construction in progress includes costs primarily attributable to the purchase
of gas-fired turbines for projects currently under development.
4. Results of Unconsolidated Investments in Power Projects
The Company has unconsolidated investments in power projects which are accounted
for under the equity method. Investments in less-than-majority-owned affiliates
and the nature and extent of these investments change over time. The combined
results of operations and financial position of the Company's equity-basis
affiliates are summarized below (in thousands):
Six Months Ended June 30,
------------------------
1999 1998
----------- ----------
Condensed Combined Statements of Operations:
Revenue ...................................... $ 231,531 $ 187,216
Net income ................................... $ 48,001 $ 19,429
Company's share of net income ................ $ 18,321 $ 6,853
June 30, December 31,
------------------------
1999 1998
----------- ----------
Condensed Combined Balance Sheets:
Assets ....................................... $1,315,950 $1,274,202
Liabilities .................................. $1,030,275 $1,000,812
The following details the Company's income from investments in unconsolidated
power projects and the service contract revenue recorded by the Company related
to those power projects (in thousands):
Service
Income Contract Revenue
------------------- -------------------
Ownership Six Months Ended June 30,
Interest 1999 1998 1999 1998
---------- -------- -------- -------- --------
Sumas Power Plant (1) .... -- $ 14,243 $ 2,872 $ 1,322 $ 809
Gordonsville Power Plant . 50% 1,872 1,785 -- --
Lockport Power Plant ..... 11.4% 1,980 1,785 -- --
Texas Cogeneration Company -- -- 2,922 -- 2,749
Bayonne Power Plant ...... 7.5% 1,912 406 -- --
Kennedy International
Airport Power Plant ..... 50% (1,592) (2,686) 418 --
Sheridan Gas Fields ...... 20% 100 -- -- --
Auburndale Power Plant ... 5% (273) (590) -- --
Stony Brook Power Plant .. 50% (57) 231 468 --
Agnews Power Plant ....... 20% (54) (98) 1,010 948
Aidlin Power Plant ....... 50% 190 226 1,200 1,638
-------- -------- -------- --------
Total .......... $ 18,321 $ 6,853 $ 4,418 $ 6,144
======== ======== ======== ========
7
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1999
(1) On December 31, 1998, the Partnership agreement governing Sumas
Cogeneration Company, L.P. ("Sumas") was amended changing the distributions
schedule for the Company from the previously amended agreement dated September
30, 1997. The newly amended agreement reflects the earnings the Company was
entitled to under that agreement from a variable payment schedule to a fixed
payment schedule. On September 30, 1997, the partnership agreement was amended
changing the distribution percentages to the partners. As provided for in the
amendment, the Company's percentage share of the project's cash flow increased
from 50% to approximately 70% through June 30, 2001, based on certain specified
payments. Thereafter, the Company will receive 50% of the project's cash flow
until a 24.5% pre-tax rate of return on its original investment is achieved, at
which time the Company's equity interest in the partnership will be reduced to
0.1%. As a result of the amendment of the partnership agreement and the receipt
of certain distributions during 1997, the Company's investment in Sumas was
reduced to zero. Because the investment has been reduced to zero and there are
no continuing obligations of the Company related to Sumas, the Company expects
that income recorded in future periods will approximate the amount of cash
received from partnership distributions.
5. Common Stock and Senior Notes Offering
On March 26, 1999, the Company completed a public offering of 6,000,000 shares
of its common stock at $31.00 per share. The net proceeds from this public
offering were approximately $177.9 million. Additionally, in April 1999, the
Company sold an additional 900,000 shares of common stock at $31.00 per share
pursuant to the exercise of the underwriters' over-allotment option for net
proceeds of approximately $26.7 million.
On March 29, 1999, the Company completed a public offering of $250.0 million of
its 7-5/8% Senior Notes Due 2006 ("Senior Notes Due 2006") and $350.0 million of
its 7-3/4% Senior Notes Due 2009 ("Senior Notes Due 2009"). The Senior Notes Due
2006 bear interest at 7-5/8% per year, payable semi-annually on April 15 and
October 15 each year and mature on April 15, 2006. The Senior Notes Due 2006 are
not redeemable prior to maturity. The Senior Notes Due 2009 bear interest at
7-3/4% per year, payable semi-annually on April 15 and October 15 each year and
mature on April 15, 2009. The Senior Notes Due 2009 are not redeemable prior to
maturity. After deducting underwriting discounts and expenses of the offering,
the aggregate net proceeds from the sale of the Senior Notes were approximately
$588.3 million.
The net proceeds from the sale of the common stock, the Senior Notes Due 2006,
and the Senior Notes Due 2009 were used as follows: (i) $120.6 million to
refinance indebtedness relating to the Gilroy Power Plant, (ii) $77.6 million to
repay indebtedness under a bridge facility provided by Credit Suisse First
Boston to finance a portion of the purchase price to acquire the steam fields
that service the Sonoma County Power Plants, (iii) $50.0 million to repay
outstanding borrowings under our revolving credit facility, $23.4 million of
which was incurred to finance a portion of the steam fields that service the
Sonoma County Power Plants, (iv) $25.0 million to complete the expansion of the
Clear Lake Power Plant, (v) approximately $400.0 million to finance a portion of
power generation facilities currently under construction and the projects
currently under development, and (vi) the remaining $96.3 million will be used
for general corporate purposes. Transaction costs incurred in connection with
the Senior Notes offerings were recorded as a deferred charge and are amortized
over the respective lives of the Senior Notes Due 2006 and the Senior Notes Due
2009 using the effective interest rate method.
8
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1999
6. Acquisitions
Unocal Transaction
On March 19, 1999, the Company completed the acquisition of Unocal Corporation's
Geysers geothermal steam fields in northern California for approximately $102.1
million. The steam fields fuel the Company"s 12 Sonoma County power plants,
totaling 544 megawatts of capacity. The Company purchased these plants from
Pacific Gas & Electric Company ("PG&E") on May 7, 1999.
PG&E Transactions
On May 7, 1999, the Company completed the acquisitions from PG&E, of 12 Sonoma
County and 2 Lake County power plants located at The Geysers, California for
approximately $212.8 million. The acquisitions were financed with a 24 year
operating lease (see Note 10). The Company's geothermal steam fields fuel the
facilities, which have a combined capacity of approximately 700 megawatts of
electricity. All of the electricity generated from the facilities is sold into
the California energy market, with the exception of an agreement entered into on
April 29, 1999 to sell to Commonwealth Energy Corporation 75 megawatts of
geothermal electricity in 1999, 100 megawatts in 2000, and 125 megawatts in 2001
and through June 2002.
7. Construction Financing
On January 4, 1999, the Company entered into a Credit Agreement with ING (U.S.)
Capital LLC ("ING") to provide up to $265.0 million of non-recourse project
financing for the construction of the Pasadena facility expansion. As of June
30, 1999, $79.2 million was outstanding as a construction loan under the
agreement. The outstanding loan bears interest at ING's base rate plus an
applicable margin or at LIBOR plus an applicable margin and is payable
quarterly. The construction loan will convert to a term loan once the project
has completed construction. The construction loan will mature on or before July
1, 2000, but is subject to an extension to October 1, 2000 if there are
sufficient construction funds available. The term loan will be available for a
period not to exceed five years from the construction loan maturity date. In
connection with the Credit Agreement, the Company entered into a $10.0 million
letter of credit facility. At June 30, 1999, there were no letters of credit
outstanding under the facility.
8. Revolving Credit Facility and Line of Credit
The Company maintains a credit facility of $100.0 million, which is available
through a consortium of commercial lending institutions with The Bank of Nova
Scotia as agent. A maximum of $50.0 million of the credit facility may be
allocated to letters of credit. At June 30, 1999, the Company had no borrowings
and $20.9 million of letters of credit outstanding under the credit facility.
Borrowings bear interest at The Bank of Nova Scotia's base rate plus an
applicable margin or at LIBOR plus an applicable margin. Interest is paid on the
last day of each interest period for such loans, at least quarterly. The credit
facility specifies that the Company maintain certain covenants, with which the
Company was in compliance as of June 30, 1999. Commitment fees related to this
line of credit are charged based on 0.375% of committed unused credit.
At June 30, 1999, the Company had a loan facility with Union Bank with available
borrowings totaling $1.1 million. As of June 30, 1999, the Company had no
borrowings and $74,000 of letters of credit outstanding under the facility.
Additionally, the Company had a $12.0 million letter of credit outstanding with
The Bank of Nova Scotia to secure performance of the Clear Lake Power Plant.
9
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1999
9. Earnings per Share
<TABLE>
<CAPTION>
June 30, 1999 June 30, 1998
---------------------------- ----------------------------
Net Net
(in thousands, except per share amounts) Income Shares EPS Income Shares EPS
------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Three Months:
Basic earnings per common share:
Income before extraordinary charge .... $ 18,710 26,923 $ 0.69 $ 11,928 20,105 $ 0.59
Extraordinary charge net of tax benefit
of $793 and $207 ...................... 1,150 (0.04) 302 (0.01)
-------- ------ -------- ------
Basic earnings per common share ....... $ 17,560 26,923 $ 0.65 $ 11,626 20,105 $ 0.58
======== ====== ====== ======== ====== ======
Common shares issuable upon
Exercise of stock options using
Treasury stock method ............... 1,601 1,021
------ ------
Diluted earnings per common share:
Income before extraordinary charge .... $ 18,710 28,524 $ 0.66 $ 11,928 21,126 $ 0.56
Extraordinary charge net of tax benefit
of $793 and $207 ..................... 1,150 (0.04) 302 (0.01)
-------- ------ -------- ------
Diluted earnings per share ............ $ 17,560 28,524 $ 0.62 $ 11,626 21,126 $ 0.55
======== ====== ====== ======== ====== ======
Six Months:
Basic earnings per common share:
Income before extraordinary charge .... $ 22,560 23,759 $ 0.95 $ 8,871 20,056 $ 0.44
Extraordinary charge net of tax benefit
of $793 and $207 ..................... 1,150 (0.05) 302 (0.01)
-------- ------ -------- ------
Basic earnings per share .............. $ 21,410 23,759 $ 0.90 $ 8,569 20,056 $ 0.43
======== ====== ====== ======== ====== ======
Common shares issuable upon
Exercise of stock options using
Treasury stock method ............... 1,476 994
------ ------
Diluted earnings per common share:
Income before extraordinary charge .... $ 22,560 25,235 $ 0.89 $ 8,871 21,050 $ 0.42
Extraordinary charge net of tax benefit
of $793 and $207 ..................... 1,150 (0.04) 302 (0.01)
-------- ------ -------- ------
Diluted earnings per share ............ $ 21,410 25,235 $ 0.85 $ 8,569 21,050 $ 0.41
======== ====== ====== ======== ====== ======
</TABLE>
For the three months ended June 30, 1999, the Company recognized an
extraordinary charge of $1.2 million or $0.04 per share (net of tax benefit of
$793,000) representing the write off of deferred financing costs related to
non-recourse project financing for the Gilroy Power Plant. The financing
agreement was terminated and the outstanding balance of $120.6 million was
repaid in April of 1999. For the three months ended June 30, 1998, the Company
recognized an extraordinary charge of $302,000 or $0.01 per share (net of tax
benefit of $207,000) as a result of the repurchase of $4.0 million of the
10-1/2% Senior Notes Due 2006. The notes were redeemed at a premium plus accrued
interest to the date of repurchase.
Unexercised employee stock options to purchase 15,000 and 48,000 shares of the
Company's common stock during the six months ended June 30, 1999 and 1998,
respectively, were not included in the computation of diluted shares outstanding
because such inclusion would be anti-dilutive.
10. Commitments and Contingencies
Production Royalties and Leases -- The Company is committed under several
geothermal leases and right-of-way, easement and surface agreements. The
geothermal leases generally provide for royalties based on production revenue
with reductions for property taxes paid. The right-of-way, easement and surface
agreements are based on flat rates and are not material. Certain properties also
have net profits and overriding royalty interests ranging from approximately
1.45% to 28%, which are in addition to the land royalties. Most lease agreements
contain clauses providing for minimum lease payments to lessors if production
temporarily ceases or if production falls below a specified level.
The Company leases its corporate offices and regional offices in San Jose,
California, Boston, Massachusetts, Houston, Texas and Pleasanton, California,
under noncancellable operating leases expiring
10
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1999
through 2002. Future minimum lease payments under these leases for the remainder
of 1999 are approximately $1.0 million.
Cogeneration Facilities Operating and Land Leases - The Company entered into
long-term operating leases in June 1995, April 199, August 1998 and May 1999 for
its Watsonville, King City, Greenleaf, Sonoma and Lake County cogeneration
facilities and the land lease for the Pasadena Power Plant. Future minimum lease
payments under these leases for the remainder of 1999 are approximately $31.1
million.
In May 1999, the Company entered into a sale and leaseback transaction for
certain plant and equipment located at The Geysers, California for a net book
value of $231.8 million. Included in the transaction were the 12 Sonoma County
and 2 Lake County power plants purchased from PG&E on May 7, 1999 (see Note 6),
as well as the Sonoma Power Plant acquired from SMUD in 1998. Under the terms of
the agreement, the Company received $18.5 million and recorded a deferred gain
of $15.2 million on the balance sheet. The deferred gain is being amortized over
the term of the lease through May 2022.
Natural Gas Purchases -- The Company enters into short-term and long-term gas
purchase contracts with third parties to supply gas to
its gas-fired cogeneration projects.
Capital expenditures -- At June 30, 1999, the Company is under contract with
Siemens Westinghouse Power Corporation for a total of $814.9 million for the
purchase of 23 turbines related to 11 development projects. Approximate payments
related to these turbines is $369.1 million for 1999.
Litigation
On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund
("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and
certain other parties, including the Company. Some of Indeck's claims relate to
Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville
Energy L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s
acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck claimed that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortuously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. In April 1999, the court granted Calpine Gordonsville
and Calpine Auburndale's motions to dismiss with prejudice, a decision which has
been appealed by Indeck. The Company is unable to predict the outcome of these
proceedings.
There is currently a dispute between Texas-New Mexico Power Company ("TNP") and
Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear Lake
Power Plant, regarding certain costs and other amounts that TNP has withheld
from payments due under the power sales agreement from August 1997 until October
1998. TNP has withheld approximately $450,000 per month related to transmission
charges. In October 1997, CLC filed a petition for declaratory order with the
Texas Public Utilities Commission ("Texas PUC") requesting a declaration that
TNP's withholding is in error, which petition is currently pending. Also, as of
June 30, 1999, TNP has withheld approximately $7.7 million of standby power
charges. In addition to the Texas PUC petition, CLC filed an action in Texas
courts on October 2, 1997, alleging TNP's breach of the power sales agreement
and is seeking refund of the standby charges. Both the Texas PUC action and the
court action have been put on hold pending completion of a settlement. A final
order was issued by the Texas PUC on July 15, 1999, approving the settlement
documentation which includes an $8.0 million cash payment by TNP to CLC.
An action was filed against Lockport Energy Associates, L.P. ("LEA") and the New
York Public Service Commission ("NYPSC") in August 1997 by New York State
Electricity and Gas Company ("NYSEG") in the Federal District Court for the
Northern District of New York. NYSEG has requested the Court to direct NYPSC and
the Federal Energy Regulatory Commission (the "FERC") to modify contract rates
to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a
cross-claim alleging that the FERC violated the Public Utility Regulatory
Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by
11
<PAGE>
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
June 30, 1999
failing to reform the NYSEG contract that was previously approved by the NYPSC.
Although it is unable to predict the outcome of this case, in any event, the
Company retains the right to require The Brooklyn Union Gas Company ("BUG") to
purchase the Company's interest in the Lockport Power Plant for $18.9 million,
less equity distributions received by the Company, at any time before December
19, 2001.
The Company is involved in various other claims and legal actions arising out of
the normal course of business. The Company does not expect that the outcome of
these proceedings will have a material adverse effect on the Company's financial
position or results of operations, although no assurance can be given in this
regard.
12
<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.
Management Overview
Calpine is engaged in the development, acquisition, ownership, and operation of
power generation facilities and the sale of electricity and steam principally in
the United States. At June 30, 1999, we had interests in 37 power plants and
steam fields predominantly in the United States, having an aggregate capacity of
3,627 megawatts.
On January 4, 1999, we completed the acquisition of a 20% interest in 82 billion
cubic feet of proven natural gas reserves located in the Sacramento basin of
Northern California. We paid approximately $14.9 million for $13.0 million in
redeemable non-voting preferred stock and 20% of the outstanding common stock of
Sheridan California Energy, Inc ("SCEI"). Additionally, we signed a ten year gas
contract enabling us to purchase 100% of SCEI's production.
On February 17, 1999, we announced that the Delta Energy Center met the
California Energy Commission's Data Adequacy requirements. This ruling stated
that our Application for Certification contained adequate information for the
California Energy Commission to begin its analysis of the power plant's
environmental impacts and proposed mitigation. The Delta Energy Center, an 880
megawatt gas-fired power plant located at the Dow Chemical facility in
Pittsburg, California, is the first power plant that will be developed, owned
and operated under a joint venture with Bechtel Enterprises, and will provide
power to the Pittsburg, California and the greater San Francisco Bay Area. The
gas-fired power plant is to be constructed by Bechtel and operated by us.
On February 17, 1999, we announced plans to develop, own and operate a 545
megawatt gas-fired power plant in Westbrook, Maine. We acquired the development
rights for the Westbrook Power Plant from Genesis Power Corporation. This power
plant is scheduled to begin power deliveries by the end of 2000, and will serve
the New England market.
On February 24, 1999, we announced plans to develop, own and operate a 600
megawatt gas-fired power plant located in San Jose, California. This power
plant, called the Metcalf Energy Center, is the second power plant to be
developed under the joint venture with Bechtel Enterprises, and will provide
electricity to the San Francisco Bay area.
On March 19, 1999, we completed the acquisition of Unocal Corporation's Geysers
geothermal steam fields in northern California for approximately $102.1 million.
The steam fields fuel our 12 Sonoma County
<PAGE> 13
power plants, totaling 544 megawatts of capacity. We purchased these plants from
PG&E on May 7, 1999 (see Note 6 to the Notes to Consolidated Financial
Statements).
On April 14, 1999, we received approval from the California Energy Commission to
construct a 545 megawatt gas-fired power plant near Yuba City, California. This
power plant, called the Sutter Power Plant, was the first new power plant
approved in California's deregulated power industry. Electricity produced by the
Sutter Power Plant will be sold into California's energy market.
On April 22, 1999, we entered into a joint venture with GenTex Power Corporation
to develop, own and operate a 545 megawatt gas-fired power plant in Bastrop
County, Texas, called Lost Pines I. Construction of this power plant is expected
to begin in October 1999. We will manage all phases of the plant's development
process, with GenTex and ourselves jointly operating the plant. The output from
Lost Pines I will be divided equally, with GenTex selling its portion to its
customer base, while we will sell our portion to the wholesale power market in
Texas.
On April 23, 1999, we entered into a joint agreement with Pinnacle West Capital
Corporation to develop, own and operate a 545 megawatt gas-fired power plant
located in Phoenix, Arizona. This plant, called the West Phoenix Power Plant,
will provide power to the Phoenix metropolitan area, and construction will
commence in 2000.
On May 7, 1999, we completed the acquisitions from PG&E, of 12 Sonoma County and
2 Lake County power plants for approximately $212.8 million. The acquisitions
were financed with a 24 year operating lease. Our geothermal steam fields fuel
the facilities, which have a combined capacity of approximately 694 megawatts of
electricity. All of the generation from the facilities is sold to the California
energy market, with the exception of an agreement entered into on April 29,
1999, to sell to Commonwealth Energy Corporation 75 megawatts of geothermal
electricity in 1999, 100 megawatts in 2000, and 125 megawatts in 2001 and
through June 2002. Historically, we have served as a steam supplier for these
facilities, which had been owned and operated by PG&E. These acquisitions have
enabled us to consolidate our operations in The Geysers into a single ownership
structure and to integrate the power plant and steam field operations, allowing
us to optimize the efficiency and performance of the facilities. We believe that
these acquisitions provide us with significant synergies that leverage our
expertise in geothermal power generation and position us to benefit from the
demand for "green" energy in the competitive market.
On June 21, 1999, we acquired the rights to build, own and operate a 545
megawatt gas-fired power plant located in Ontelaunee Township, Pennsylvania. The
plant, called the Ontelaunee Energy Center, will provide power to residences and
businesses throughout the Pennsylvania-New Jersey-Maryland power pool.
Construction will commence in 2000 and the plant is scheduled to begin
production in 2001.
On July 26, 1999,we announced plans to enter into a $1.0 billion revolving
construction credit facility. The non-recourse credit facility will serve as a
key component of our development program and will be utilized to finance the
construction of a diversified portfolio of gas-fired power plants. The four-year
credit facility will be used initially to fund the completion of the Sutter,
South Point, Magic Valley, and Westbrook power plants currently under
construction. The construction facility will be refinanced in the longer-term
capital markets prior to its four-year maturity.
Selected Operating Information
Set forth below is certain selected operating information for the power plants
and steam fields, for which results are consolidated in our statements of
operations. The information set forth under power plants consists of the results
for the West Ford Flat Power Plant, Bear Canyon Power Plant, Greenleaf 1 & 2
Power Plants, Watsonville Power Plant, King City Power Plant, Gilroy Power
Plant, the Bethpage Power Plant since its acquisition on February 5, 1998, the
Texas City and Clear Lake Power Plants since their acquisition on March 31,
1998, the Pasadena Power Plant since it began commercial operation on July 7,
1998, the Sonoma Power Plant since its acquisition on July 17, 1998, the
Pittsburg Power Plant since its acquisition on July 21, 1998, and the 12 Sonoma
County and 2 Lake County power plants purchased from PG&E on May 7, 1999. The
information set forth under steam fields consists of the results for the Thermal
<PAGE> 14
Power Company Steam Fields prior to the acquisition.
(in thousands, except Three Months Ended Six Months Ended
price per kilowatt hour) June 30, June 30,
------------------------ -----------------------
1999 1998 1999 1998
----------- ----------- ---------- ----------
Power Plants:
Electricity revenues:
Energy ............... $ 104,748 $ 70,446 $ 177,305 $ 93,735
Capacity ............. $ 61,410 $ 57,616 $ 106,155 $ 67,103
Megawatt hours produced 3,140,923 1,868,067 5,516,805 2,217,659
Average energy price
per kilowatt hour ... $ 0.0334 $ 0.0377 $ 0.0321 $ 0.0423
Steam Fields:
Steam Revenue: ......... $ 10,138 $ 7,346 $ 20,862 $ 17,960
Megawatt hours produced 500,954 452,571 1,192,722 981,114
Average price per
kilowatt hour ....... $ 0.0202 $ 0.0162 $ 0.0175 $ 0.0183
Megawatt hours produced at the power plants increased 68% and 148% for the three
and six months ended June 30, 1999 as compared with the same periods in 1998.
This was primarily due to 1,795,553 and 3,626,670 megawatt hours of production
at the Pittsburg, Pasadena, Clear Lake, Texas City and Bethpage Power Plants for
the three and six months ended June 30, 1999 as well as the additional megawatt
hours produced at the 14 geothermal power plants purchased from PG&E on May 7,
1999.
Due to the consolidation of the power plants purchased from PG&E on May 7, 1999,
our steam fields will no longer recognize any additional steam revenue.
OTHER FINANCIAL DATA RATIOS
Set forth below are certain other financial data and ratios for the periods
indicated (in thousands, except ratio data):
Three Months Ended Six Months Ended
June 30, June 30,
------------------- -------------------
1999 1998 1999 1998
-------- -------- -------- --------
Depreciation and amortization ...... $ 25,994 $ 19,522 $ 45,449 $ 32,104
Interest expense per indenture .... $ 28,931 $ 23,482 $ 52,034 $ 43,212
EBITDA ............................. $100,789 $ 67,557 $151,927 $ 93,374
EBITDA to interest expense .........
per indenture hours produced ...... $ 3.48x $ 2.88x $ 2.92x $ 2.16x
EBITDA is defined as income from operations plus depreciation, capitalized
interest, other income, non-cash charges and cash received from investments in
power projects, reduced by the income from unconsolidated investments in power
projects. EBITDA is presented not as a measure of operating results, but rather
as a measure of our ability to service debt. EBITDA should not be construed as
an alternative either (i) to income from operations (determined in accordance
with generally accepted accounting principles) or (ii) to cash flows from
operating activities (determined in accordance with generally accepted
accounting principles).
Interest expense per indenture is defined as total interest expense plus
one-third of all operating lease obligations, dividends paid in respect to
preferred stock and cash contributions to any employee stock ownership plan used
to pay interest on loans to purchase capital stock of the company.
15
<PAGE>
Results of Operations
Three and Six Months Ended June 30, 1999 Compared to Three and Six Months Ended
June 30, 1998 Consolidated Operations. (Dollars in thousands)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- -----------------------
% %
1999 1998 Change 1999 1998 Change
Revenue: ------- -------- ------ -------- -------- ------
Electricity and steam sales. $176,296 $135,408 30% $304,322 $178,798 70%
Service contract revenue ... 6,466 3,048 112% 13,238 8,529 55%
Income from unconsolidated
investments in power
projects .................. 7,509 3,099 142% 18,321 6,853 167%
Interest on loans to power
projects .................. 406 42 867% 709 2,562 -72%
-------- -------- ------ -------- -------- ------
Total revenue ....... $190,677 $141,597 35% $336,590 $196,742 71%
======== ======== ====== ======== ======== ======
Revenue -- Total revenue increased 35% and 71% to $190.7 million and $336.6
million for the three months and six months ended June 30, 1999 compared to
$141.6 million and $196.7 million in 1998.
Electricity and steam sales revenue increased 30% to $176.3 million for the
three months ended June 30, 1999 compared to $135.4 million in the same period
in 1998. The increase is primarily attributable to the consolidation of our
Geysers operation in Northern California during the second quarter of calendar
1999, which increased electricity revenues by $20.1 million. The Pasadena Power
Plant, which became operational in July 1998, contributed $13.9 million in
revenue during 1999. The acquisition of the Pittsburg Power Plant accounted for
$5.2 million in additional electricity revenues in 1999. These increases were
partially offset by a decrease of $11.1 million at the Bear Canyon and West Ford
Flat Power Plants relating to the expiration of the fixed priced period of their
power sales agreements. Consequently, the price of electricity for these two
power plants was significantly reduced compared to the price for the same period
in 1998. For the six months ended June 30, 1999, electricity and steam revenues
increased 70% to $304.3 million as compared to $178.8 million for the same
period a year ago. These increases are primarily due an increase of $116.5
million for power plants that were acquired during the first half of 1998, and
$32.7 million for our Pasadena plant that became operational in the third
quarter of 1998, partially offset by a decrease of $21.6 million at the Bear
Canyon and West Ford Flat Power Plants relating to the expiration of the fixed
priced period of their power sales agreements.
Service contract revenue increased to $6.5 million and $13.2 million for
the three and six months ended June 30, 1999 compared to $3.0 million and $8.5
million for the same periods in 1998. The increase was primarily attributable to
third party excess gas sales, as well as an increase for fuel management fees.
Income from unconsolidated investments in power projects increased 142% to
$7.5 million for the three months ended June 30, 1999 compared to $3.1 million
for the same period in 1998. The increase is primarily attributable to an
increase of $4.1 million of equity income from our investment in Sumas , and
$349,000 of equity income from our investment in the Bayonne Power Plant which
was acquired in March 1998. For the six months ended June 30, 1999, income from
unconsolidated investments in power projects increased 167% to $18.3 million as
compared to $6.9 million for the same period a year ago. This increase is
primarily attributable to an increase of $11.4 million of equity income from our
investment in Sumas, an increase of $1.5 million of equity income from our
investment in the Bayonne Power Plant , and an increase of $1.1 million from our
Kennedy International Airport Power Plant . These increases were partially
offset by a reduction of $2.9 million in equity income from our Texas City and
Clear Lake Power Plants, which were consolidated on March 31, 1998.
Interest income on loans to power projects increased to $406,000 for the
three months ended June 30, 1999 compared to $42,000 in 1998. The increase is
attributable to dividend income received from Sheridan California Energy, Inc.
For the six months ended June 30, 1999, interest income on loans to power
projects decreased to $709,000 compared to $2.6 million for the same period a
year ago. The decrease is primarily related to the acquisition of the remaining
50% interest in Texas Cogeneration Company on March 31, 1998, offset by dividend
income received from Sheridan California Energy, Inc.
16
<PAGE>
Cost of revenue -- Cost of revenue increased to $128.7 million and $238.2
million for the three and six months ended June 30, 1999 compared to $96.8
million and $136.1 million for the same periods in 1998. The increases of $31.9
million and $102.1 million were primarily attributable to increased plant
operating, fuel and depreciation expenses as a result of the acquisition of the
remaining interests in the Texas City, Clear Lake Power Plants on March 31,
1998, the acquisition of the remaining interest in the Bethpage Power Plant on
February 5, 1998, the acquisition of the Pittsburg Power Plant on July 21, 1998,
the consolidation of our Geysers operations on May 7, 1999 and the startup of
the Pasadena Power Plant in July of 1998.
General and administrative expenses -- General and administrative expenses
increased to $10.9 million for the three months ended June 30, 1999 compared to
$5.8 million in 1998. For the six months ended June 30, 1999, general and
administrative expenses increased to $21.0 million compared to $11.0 million for
the same period in 1998. The increases were attributable to continued growth in
personnel and associated overhead costs necessary to support the overall growth
in our operations.
Interest expense -- Interest expense increased 17% to $26.1 million for the
three months ended June 30, 1999 from $22.3 million for the same period in 1998.
The increase was primarily attributable to $11.6 million of interest associated
with the issuance of senior notes in 1999, partially offset by an increase in
capitalized interest of $8.5 million in connection with the construction of
power plants as compared to the same period in 1998. For the six months ended
June 30, 1999, interest expense increased to $47.2 million from $40.8 million
for the same period a year ago. The increase was primarily attributable to $21.8
million of interest associated with the issuances of senior notes in 1999 and
1998, partially offset by an increase in capitalized interest of $10.2 million,
and a decrease in interest expense of $5.2 million related to the retirement of
non-recourse project financing for the Greenleaf Power Plant in 1998 and the
Gilroy Power Plant in 1999.
Provision for income taxes -- The effective income tax rate was
approximately 39% for the three and six months ended June 30, 1999. The
reductions from the statutory tax rate were primarily due to depletion in excess
of tax basis benefits at our geothermal facilities, and a decrease in the
California taxes paid due to our expansion into states other than California.
Liquidity and Capital Resources
To date, we have obtained cash from our operations, borrowings under our
credit facilities and other working capital lines, sale of debt and equity, and
proceeds from non-recourse project financing. We utilized this cash to fund our
operations, service debt obligations, fund the acquisition, develop and
construct power generation facilities, finance capital expenditures and meet our
other cash and liquidity needs. The following table summarizes our cash flow
activities for the periods indicated:
Six Months Ended June 30,
-------------------------
1999 1998
----------- -----------
(in thousands)
Cash flows from:
Operating activities ......... $ 58,555 $ 23,073
Investing activities ......... (590,328) (174,923)
Financing activities ......... 755,528 203,696
----------- -----------
Total ................ $ 223,755 $ 51,846
=========== ===========
Operating activities for 1999 provided $58.6 million, consisting of
approximately $44.1 million of depreciation and amortization, $21.4 million of
net income, $25.5 million of distributions from unconsolidated investments in
power projects, $13.3 million of deferred income taxes, and a $7.2 million net
increase in operating liabilities. This was offset by $34.6 million net increase
in operating assets and $18.3 million of income from unconsolidated investments.
Investing activities for 1999 used $590.3 million, primarily due to $102.2
million for the acquisition of steam fields from Unocal, $14.9 million for the
acquisition of a 20% interest in Sheridan California Energy Inc., a $15.8
million increase in restricted cash, $79.3 million of capital expenditures
related to the
17
<PAGE>
construction of the Pasadena Power Plant Expansion, $344.6 million of other
capital expenditures principally for turbine purchases and for the Clear Lake
Expansion project, $33.8 million of capitalized project development costs, $14.0
million of interest capitalized on construction projects, $8.4 million of
additional loans to principal owners of power plants, $655,000 for the
acquisition of additional investments, offset by $1.9 million of maturities of
collateral securities in connection with the King City Power Plant, the
repayment of $3.1 million of outstanding loans, and $18.4 million from the sale
and leaseback transaction of the Geysers Power Company plants.
Financing activities for 1999 provided $755.5 million of cash consisting of
$79.2 million of borrowings for the construction of the Pasadena Power Plant,
$77.6 million of borrowings related to a bridge facility, $794.7 million of net
proceeds from additional equity and senior debt financings received in March and
April of 1999, and $1.2 million for the issuance of common stock for our
Employee Stock Purchase Plan, partially offset by $120.6 million in repayment of
non-recourse project financing in April 1999, and $77.6 million of repayments
related to a bridge facility.
At June 30, 1999, cash and cash equivalents were $320.3 million and working
capital was $346.4 million. For 1999, cash and cash equivalents increased by
$223.8 million and working capital increased by $259.5 million as compared to
December 31, 1998.
As a developer, owner and operator of power generation facilities, we are
required to make long-term commitments and investments of substantial capital
for our projects. We historically have financed these capital requirements with
cash from operations, borrowings under our credit facilities, other lines of
credit, construction financing, non-recourse project financing or long-term
debt, and the sale of equity.
We continue to evaluate current and forecasted cash flow as a basis for
financing operating requirements and capital expenditures. We believe that we
will have sufficient liquidity from cash flow from operations, borrowings
available under the lines of credit and working capital to satisfy all
obligations under outstanding indebtedness, to finance anticipated capital
expenditures and to fund working capital requirements for the next twelve
months.
On January 4, 1999, the Company entered into a Credit Agreement with ING to
provide up to $265.0 million of non-recourse project financing for the
construction of the Pasadena facility expansion. As of June 30, 1999, $79.2
million was outstanding as a construction loan under the agreement. The
outstanding loan bears interest at ING's base rate plus an applicable margin or
at LIBOR plus an applicable margin and is payable quarterly. The construction
loan will convert to a term loan once the project has completed construction.
The construction loan will mature on or before July 1, 2000, but is subject to
an extension to October 1, 2000 if there are sufficient construction funds
available. The term loan will be available for a period not to exceed five years
from the construction loan maturity date. In connection with the Credit
Agreement, we entered into a $10.0 million letter of credit facility. At June
30, 1999, there were no letters of credit outstanding under the facility.
On March 26, 1999, we completed a public offering of 6,000,000 shares of
our common stock at $31.00 per share. The net proceeds from this public offering
were approximately $177.9 million. Additionally, in April 1999, we sold an
additional 900,000 shares of common stock at $31.00 per share pursuant to the
exercise of the underwriters' over-allotment option for net proceeds of
approximately $26.7 million.
On March 29, 1999, we completed a public offering of $250.0 million of our
7-5/8% Senior Notes Due 2006 and of our $350.0 million 7-3/4% Senior Notes Due
2009. After deducting underwriting discounts and expenses of the offering, the
aggregate net proceeds from the sale of the Senior Notes were approximately
$588.3 million. The Senior Notes Due 2006 bear interest at 7-5/8% per year,
payable semi-annually on April 15 and October 15 each year and mature on April
15, 2006. The Senior Notes Due 2006 are not redeemable prior to maturity. The
Senior Notes Due 2009 bear interest at 7-3/4% per year, payable semi-annually on
April 15 and October 15 each year and mature on April 15, 2009. The Senior Notes
Due 2009 are not redeemable prior to maturity.
The net proceeds from the sale of the common stock, the Senior Notes
18
<PAGE>
Due 2006, and the Senior Notes Due 2009 were used as follows: (i) $120.6 million
to refinance indebtedness relating to the Gilroy Power Plant, (ii) $77.6 million
to repay indebtedness under a bridge facility provided by Credit Suisse First
Boston to finance a portion of the purchase price to acquire the steam fields
that service the Sonoma County power plants, (iii) $50.0 million to repay
outstanding borrowings under our revolving credit facility, $23.4 million of
which was incurred to finance a portion of the steam fields that service the
Sonoma Power Plants, (iv) $25.0 million to complete the expansion of the Clear
Lake Power Plant, (v) approximately $400.0 million to finance a portion of power
generation facilities currently under construction and the projects currently
under development, and (vi) the remaining $96.3 million will be used for general
corporate purposes. Transaction costs incurred in connection with the Senior
Notes offering were recorded as a deferred charge and are amortized over the
respective lives of the Senior Notes Due 2006 and the Senior Notes Due 2009
using the effective interest rate method.
At June 30, 1999, we also had $105.0 million of outstanding 9-1/4% Senior
Notes Due 2004, which mature on February 1, 2004, with interest payable
semi-annually on February 1 and August 1 of each year. In addition, we had
$171.8 million of outstanding 10-1/2% Senior Notes Due 2006, which mature on May
15, 2006, with interest payable semi-annually on May 15 and November 15 of each
year. During 1997, we issued $275.0 million of 8-3/4% Senior Notes Due 2007,
which mature on July 15, 2007, with interest payable semi-annually on January 15
and July 15 of each year. During 1998, we issued $400.0 million of 7-7/8% Senior
Notes Due 2008, which mature on April 1, 2008, with interest payable
semi-annually on April 1 and October 1 of each year.
At June 30, 1999, we had a $100.0 million revolving credit facility
available with a consortium of commercial lending institutions. We had no
borrowings and $20.9 million of letters of credit outstanding under the credit
facility (See Note 8 to the Notes to Consolidated Financial Statements). The
credit facility contains certain restrictions that limit or prohibit, among
other things, our ability to incur indebtedness, make payments of certain
indebtedness, pay dividends, make investments, engage in transactions with
affiliates, create liens, sell assets and engage in mergers and consolidations.
At June 30, 1999, we had a $12.0 million letter of credit outstanding with
The Bank of Nova Scotia to secure performance of the Clear Lake Power Plant.
We have a $1.1 million working capital line with a commercial lender that
may be used to fund short-term working capital commitments and letters of
credit. At June 30, 1999, we had no borrowings under this working capital line
and $74,000 of letters of credit outstanding. Borrowings accrue interest at
prime plus 1%.
Outlook
Our strategy is to continue our rapid growth by capitalizing on the
significant opportunities in the power industry, primarily through our active
development and acquisition programs. In pursuing our proven growth strategy, we
utilize our extensive management and technical expertise to implement a fully
integrated approach to the acquisition, development and operation of power
generation facilities. This approach uses our expertise in design, engineering,
procurement, finance, construction management, fuel and resource acquisition,
operations and power marketing, which we believe provide us with a competitive
advantage. The key elements of our strategy are as follows:
* Development and expansion of power plants. We are actively pursuing the
development and expansion of highly efficient, low-cost, gas-fired power
plants that replace old and inefficient generating facilities and meet the
demand for new generation. Our strategy is to develop power plants in
strategic geographic locations that enable us to leverage existing power
generation assets and operate the power plants as integrated electric
generation systems. This allows us to achieve significant operating
synergies and efficiencies in fuel procurement, power marketing and
operations and maintenance.
We currently have seven new projects under construction, representing an
additional 3,440 megawatts of capacity. Of these new projects, we are
expanding our Pasadena facility by an
19
<PAGE>
aggregate of 545 megawatts. In addition, the Tiverton, Rumford, Magic
Valley, South Point, Sutter, and Westbrook power plants, which will produce
an estimated 2,895 megawatts of electricity, are currently under
construction. We have also announced plans to develop six additional power
generation facilities, totaling an estimated 3,615 megawatts of
electricity, in California, Texas, Arizona and Pennsylvania.
On July 26, 1999, we announced plans to enter into a $1.0 billion revolving
construction credit facility. The non-recourse credit facility will serve
as a key component of our development program and will be utilized to
finance the construction of a diversified portfolio of gas-fired power
plants. The four-year credit facility will be used initially to fund the
completion of the Sutter, South Point, Magic Valley, and Westbrook power
plants currently under construction. The construction facility will be
refinanced in the longer-term capital markets prior to its four-year
maturity.
* Acquisition of power plants. Our strategy is to acquire power generating
facilities that meet our stringent acquisition criteria and provide
significant potential for revenue, cash flow and earnings growth, and that
provide the opportunity to enhance the operating efficiencies of the
plants. We have significantly expanded and diversified our project
portfolio through the acquisition of power generation facilities through
the completion of 32 acquisitions to date.
* Enhance the performance and efficiency of existing power projects. We
continually seek to maximize the power generation potential of our
operating assets and minimize our operating and maintenance expenses and
fuel costs. This will become even more significant as our portfolio of
power generation facilities expands to an aggregate of 50 power plants with
an aggregate capacity of approximately 10,700 megawatts, after completion
of our projects currently under construction and in development. We focus
on operating our plants as an integrated system of power generation, which
enables us to minimize costs and maximize operating efficiencies. We
believe that achieving and maintaining a low-cost of production will be
increasingly important to compete effectively in the power generation
industry.
Risk Factors
We have substantial indebtedness that we may be unable to service and that
restricts our activities. We have substantial debt that we incurred to finance
the acquisition and development of power generation facilities. As of June 30,
1999 our total consolidated indebtedness was $1.6 billion, our total
consolidated assets were $2.5 billion and our stockholders' equity was $514.1
million. Whether we will be able to meet our debt service obligations and to
repay our outstanding indebtedness will be dependent primarily upon the
performance of our power generation facilities.
This high level of indebtedness has important consequences, including:
* limiting our ability to borrow additional amounts for working capital,
capital expenditures, debt service requirements, execution of our growth
strategy, or other purposes,
* limiting our ability to use operating cash flow in other areas of our
business because we must dedicate a substantial portion of these funds to
service the debt,
* increasing our vulnerability to general adverse economic and industry
conditions, and
* limiting our ability to capitalize on business opportunities and to react
to competitive pressures and adverse changes in government regulation.
The operating and financial restrictions and covenants in our existing debt
agreements, including the indentures relating to our outstanding senior notes
and our $100.0 million revolving credit facility, contain restrictive covenants.
Among other things these restrictions limit or prohibit our ability to:
* incur indebtedness,
* make prepayments of indebtedness in whole or in part,
* pay dividends,
* make investments,
20
<PAGE>
* engage in transactions with affiliates,
* create liens,
* sell assets, and
* acquire facilities or other businesses.
Also, if our management or ownership changes, our indentures may require us
to make an offer to purchase our outstanding notes, including the senior notes.
We cannot assure you that we will have the financial resources necessary to
purchase such notes, and our board of directors cannot waive provisions in the
indentures.
We believe that our cash flow from operations, together with other
available sources of funds, including borrowings under our existing borrowing
arrangements, will be adequate to pay principal and interest on our debt and to
enable us to comply with the terms of our debt agreements. If we are unable to
comply with the terms of our debt agreements and fail to generate sufficient
cash flow from operations in the future, we may be required to refinance all or
a portion of our existing debt or to obtain additional financing. However, we
may be unable to refinance or obtain additional financing because of our high
levels of debt and the debt incurrence restrictions under our debt agreements.
If cash flow is insufficient and refinancing or additional financing is
unavailable, we may be forced to default on our debt obligations. In the event
of a default under the terms of any of our indebtedness, the debt holders may
accelerate the maturity of our obligations, which could cause defaults under our
other obligations.
Our ability to repay our debt depends upon the performance of our
subsidiaries. Almost all of our operations are conducted through our
subsidiaries and other affiliates. As a result, we depend almost entirely upon
their earnings and cash flow to service our indebtedness, including our ability
to pay the interest on and principal of our senior notes. The non-recourse
project financing agreements of certain of our subsidiaries and other affiliates
generally restrict their ability to pay dividends, make distributions or
otherwise transfer funds to us prior to the payment of other obligations,
including operating expenses, debt service and reserves.
Our subsidiaries and other affiliates are separate and distinct legal
entities and have no obligation to pay any amounts due on our senior notes, and
do not guarantee the payment of interest on or principal of these notes. The
right of our senior note holders to receive any assets of any of our
subsidiaries or other affiliates upon our liquidation or reorganization will be
subordinated to the claims of any subsidiaries' or other affiliates' creditors
(including trade creditors and holders of debt issued by our subsidiaries or
affiliates).
While the indentures impose limitations on our ability and the ability of
our subsidiaries to incur additional indebtedness, the indentures do not limit
the amount of non-recourse project financing that our subsidiaries may incur to
finance new power generation facilities.
We may be unable to secure additional financing in the future. Each power
generation facility that we acquire or develop will require substantial capital
investment. Our ability to arrange financing and the cost of the financing are
dependent upon numerous factors. These factors include:
* general economic and capital market conditions,
* conditions in energy markets,
* regulatory developments,
* credit availability from banks or other lenders,
* investor confidence in the industry and in us,
* the continued success of our current power generation facilities, and
* provisions of tax and securities laws that are conducive to raising
capital.
Financing for new facilities may not be available to us on acceptable terms
in the future. We have financed our existing power generation facilities using a
variety of leveraged financing structures, primarily consisting of non-recourse
project financing and lease obligations. As of June 30, 1999, we had
approximately $1.6 billion of total consolidated indebtedness, of which
approximately 5% represented construction financing. Each construction
financing, non-recourse project financing and lease obligation is
21
<PAGE>
structured to be fully paid out of cash flow provided by the facility or
facilities. In the event of a default under a financing agreement which we do
not cure, the lenders or lessors would generally have rights to the facility and
any related assets. In the event of foreclosure after a default, we might not
retain any interest in the facility. While we intend to utilize non-recourse or
lease financing when appropriate, market conditions and other factors may
prevent similar financing for future facilities. We do not believe the existence
of non-recourse or lease financing will significantly affect our ability to
continue to borrow funds in the future in order to finance new facilities.
However, it is possible that we may be unable to obtain the financing required
to develop our power generation facilities on terms satisfactory to us.
We have from time to time guaranteed certain obligations of our
subsidiaries and other affiliates. Our lenders or lessors may also require us to
guarantee the indebtedness for future facilities. This would render our general
corporate funds vulnerable in the event of a default by the facility or related
subsidiary. Additionally, our indentures may restrict our ability to guarantee
future debt, which could adversely affect our ability to fund new facilities.
Our indentures do not limit the ability of our subsidiaries to incur
non-recourse or lease financing for investment in new facilities.
Our power project development and acquisition activities may not be
successful. The development of power generation facilities is subject to
substantial risks. In connection with the development of a power generation
facility, we must generally obtain:
* necessary power generation equipment,
* governmental permits and approvals,
* fuel supply and transportation agreements,
* sufficient equity capital and debt financing,
* electrical transmission agreements, and
* site agreements and construction contracts.
We may be unsuccessful in accomplishing any of these matters or in doing so
on a timely basis. In addition, project development is subject to various
environmental, engineering and construction risks relating to cost-overruns,
delays and performance. Although we may attempt to minimize the financial risks
in the development of a project by securing a favorable power sales agreement,
obtaining all required governmental permits and approvals and arranging adequate
financing prior to the commencement of construction, the development of a power
project may require us to expend significant amounts for preliminary
engineering, permitting and legal and other expenses before we can determine
whether a project is feasible, economically attractive or financeable. If we
were unable to complete the development of a facility, we would generally not be
able to recover our investment in the project. The process for obtaining initial
environmental, siting and other governmental permits and approvals is
complicated and lengthy, often taking more than one year, and is subject to
significant uncertainties. We cannot assure you that we will be successful in
the development of power generation facilities in the future.
We have grown substantially in recent years as a result of acquisitions of
interests in power generation facilities and steam fields. We believe that
although the domestic power industry is undergoing consolidation and that
significant acquisition opportunities are available, we are likely to confront
significant competition for acquisition opportunities. In addition, we may be
unable to continue to identify attractive acquisition opportunities at favorable
prices or, to the extent that any opportunities are identified, we may be unable
to complete the acquisitions.
Our projects under construction may not commence operation as scheduled.
The commencement of operation of a newly constructed power generation facility
involves many risks, including:
* start-up problems,
* the breakdown or failure of equipment or processes, and
* performance below expected levels of output or efficiency.
New plants have no operating history and may employ recently developed and
technologically complex equipment. Insurance is maintained to protect against
certain risks, warranties are generally obtained for
22
<PAGE>
limited periods relating to the construction of each project and its equipment
in varying degrees, and contractors and equipment suppliers are obligated to
meet certain performance levels. The insurance, warranties or performance
guarantees, however, may not be adequate to cover lost revenues or increased
expenses. As a result, a project may be unable to fund principal and interest
payments under its financing obligations and may operate at a loss. A default
under such a financing obligation could result in losing our interest in a power
generation facility.
In addition, power sales agreements entered into with a utility early in
the development phase of a project may enable the utility to terminate the
agreement, or to retain security posted as liquidated damages, if a project
fails to achieve commercial operation or certain operating levels by specified
dates or if we fail to make specified payments. In the event a termination right
is exercised, the default provisions in a financing agreement may be triggered
(rendering such debt immediately due and payable). As a result, the project may
be rendered insolvent and we may lose our interest in the project.
Our power generation facilities may not operate as planned. The continued
operation of power generation facilities involves many risks, including the
breakdown or failure of power generation equipment, transmission lines,
pipelines or other equipment or processes and performance below expected levels
of output or efficiency. Although from time to time our power generation
facilities have experienced equipment breakdowns or failures, these breakdowns
or failures have not had a significant effect on the operation of the facilities
or on our results of operations. For the six months ended June 30, 1999, our
power generation facilities have operated at an average availability of
approximately 87.3%. Although our facilities contain various redundancies and
back-up mechanisms, a breakdown or failure may prevent the facility from
performing under applicable power sales agreements. In addition, although
insurance is maintained to protect against operating risks, the proceeds of
insurance may not be adequate to cover lost revenues or increased expenses. As a
result, we could be unable to service principal and interest payments under our
financing obligations which could result in losing our interest in the power
generation facility.
Our geothermal energy reserves may be inadequate for our operations. The
development and operation of geothermal energy resources are subject to
substantial risks and uncertainties similar to those experienced in the
development of oil and gas resources. The successful exploitation of a
geothermal energy resource ultimately depends upon:
* the heat content of the extractable fluids,
* the geology of the reservoir,
* the total amount of recoverable reserves,
* operating expenses relating to the extraction of fluids,
* price levels relating to the extraction of fluids, and
* capital expenditure requirements relating primarily to the drilling of new
wells.
In connection with each geothermal power plant, we estimate the
productivity of the geothermal resource and the expected decline in
productivity. The productivity of a geothermal resource may decline more than
anticipated, resulting in insufficient reserves being available for sustained
generation of the electrical power capacity desired. An incorrect estimate by us
or an unexpected decline in productivity could lower our results of operations.
Geothermal reservoirs are highly complex. As a result, there exist numerous
uncertainties in determining the extent of the reservoirs and the quantity and
productivity of the steam reserves. Reservoir engineering is an inexact process
of estimating underground accumulations of steam or fluids that cannot be
measured in any precise way, and depends significantly on the quantity and
accuracy of available data. As a result, the estimates of other reservoir
specialists may differ materially from ours. Estimates of reserves are generally
revised over time on the basis of the results of drilling, testing and
production that occur after the original estimate was prepared. While we have
extensive experience in the operation and development of geothermal energy
resources and in preparing such estimates, we cannot assure you that we will be
able to successfully manage the development and operation of our geothermal
reservoirs or that we will accurately estimate the quantity or productivity of
our steam reserves.
23
<PAGE>
We depend on our electricity and thermal energy customers. Each of our
power generation facilities currently relies on one or more power sales
agreements with one or more utility or other customers for all or substantially
all of such facility's revenue. In addition, the sales of electricity to two
utility customers during 1998 comprised approximately 64% of our total revenue
during that year. The loss of any one power sales agreement with any of these
customers could have a negative effect on our results of operations. In
addition, any material failure by any customer to fulfill its obligations under
a power sales agreement could have a negative effect on the cash flow available
to us and on our results of operations.
We are subject to complex government regulation which could adversely
affect our operations. Our activities are subject to complex and stringent
energy, environmental and other governmental laws and regulations. The
construction and operation of power generation facilities require numerous
permits, approvals and certificates from appropriate federal, state and local
governmental agencies, as well as compliance with environmental protection
legislation and other regulations. While we believe that we have obtained the
requisite approvals for our existing operations and that our business is
operated in accordance with applicable laws, we remain subject to a varied and
complex body of laws and regulations that both public officials and private
individuals may seek to enforce. Existing laws and regulations may be revised or
new laws and regulations may become applicable to us that may have a negative
effect on our business and results of operations. We may be unable to obtain all
necessary licenses, permits, approvals and certificates for proposed projects,
and completed facilities may not comply with all applicable permit conditions,
statutes or regulations. In addition, regulatory compliance for the construction
of new facilities is a costly and time-consuming process. Intricate and changing
environmental and other regulatory requirements may necessitate substantial
expenditures to obtain permits. If a project is unable to function as planned
due to changing requirements or local opposition, it may create expensive delays
or significant loss of value in a project.
Our operations are potentially subject to the provisions of various energy
laws and regulations, including the Public Utility Regulatory Policies Act of
1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1955, as
amended ("PUHCA"), and state and local regulations. PUHCA provides for the
extensive regulation of public utility holding companies and their subsidiaries.
PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and
owners of QFs certain exemptions from certain federal and state regulations,
including rate and financial regulations.
Under present federal law, we are not subject to regulation as a holding
company under PUHCA, and will not be subject to such regulation as long as the
plants in which we have an interest (1) qualify as QFs, (2) are subject to
another exemption or waiver or (3) qualify as exempt wholesale generators
("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility
must be not more than 50% owned by an electric utility company or electric
utility holding company. In addition, a QF that is a cogeneration facility, such
as the plants in which we currently have interests, must produce electricity as
well as thermal energy for use in an industrial or commercial process in
specified minimum proportions. The QF also must meet certain minimum energy
efficiency standards. Any geothermal power facility which produces up to 80
megawatts of electricity and meets PURPA ownership requirements is considered a
QF.
If any of the plants in which we have an interest lose their QF status or
if amendments to PURPA are enacted that substantially reduce the benefits
currently afforded QFs, we could become a public utility holding company, which
could subject us to significant federal, state and local regulation, including
rate regulation. If we become a holding company, which could be deemed to occur
prospectively or retroactively to the date that any of our plants loses its QF
status, all our other power plants could lose QF status because, under FICC
regulations, a QF cannot be owned by an electric utility or electric utility
holding company. In addition, a loss of QF status could, depending on the
particular power purchase agreement, allow the power purchaser to cease taking
and paying for electricity or to seek refunds of past amounts paid and thus
could cause the loss of some or all contract revenues or otherwise impair the
value of a project. If a power purchaser were to cease taking and paying for
electricity or seek to obtain refunds of past amounts paid, there can be no
assurance that the costs incurred in connection with the project could be
recovered through sales to other purchasers. Such events could adversely affect
our ability to service our indebtedness, including our senior notes.
24
<PAGE>
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at prices based on avoided costs of energy. We do not know whether this
legislation will be passed or, if passed, what form it may take. We cannot
assure that any legislation passed would not adversely impact our existing
domestic projects.
In addition, many states are implementing or considering regulatory
initiatives designed to increase competition in the domestic power generation
industry and increase access to electric utilities' transmission and
distribution systems for independent power producers and electricity consumers.
In particular, the state of California has restructured its electric industry by
providing for a phased-in competitive power generation industry, with a power
pool and an independent system operator, and for direct access to generation for
all power purchasers outside the power exchange under certain circumstances.
Although existing QF power sales contracts are to be honored under such
restructuring, and all of our California operating projects are QFs, until the
new system is fully implemented, it is impossible to predict what impact, if
any, it may have on the operations of those projects.
We may be unable to obtain an adequate supply of natural gas in the future.
To date, our fuel acquisition strategy has included various combinations of our
own gas reserves, gas prepayment contracts and short-, medium- and long-term
supply contracts. In our gas supply arrangements, we attempt to match the fuel
cost with the fuel component included in the facility's power sales agreements,
in order to minimize a project's exposure to fuel price risk. We believe that
there will be adequate supplies of natural gas available at reasonable prices
for each of our facilities when current gas supply agreements expire. However,
gas supplies may not be available for the full term of the facilities' power
sales agreements, and gas prices may increase significantly. If gas is not
available, or if gas prices increase above the fuel component of the facilities'
power sales agreements, there could be a negative impact on our results of
operations.
Competition could adversely affect our performance. The power generation
industry is characterized by intense competition. We encounter competition from
utilities, industrial companies and other power producers. In recent years,
there has been increasing competition in an effort to obtain power sales
agreements. This competition has contributed to a reduction in electricity
prices. In addition, many states have implemented or are considering regulatory
initiatives designed to increase competition in the domestic power industry.
This competition has put pressure on electric utilities to lower their costs,
including the cost of purchased electricity.
Our international investments may face uncertainties. We have one
investment in geothermal steam fields located in Mexico and may pursue
additional international investments. International investments are subject to
unique risks and uncertainties relating to the political, social and economic
structures of the countries in which we invest. Risks specifically related to
investments in non-United States projects may include:
* risks of fluctuations in currency valuation,
* currency inconvertibility,
* expropriation and confiscatory taxation,
* increased regulation, and
* approval requirements and governmental policies limiting returns to foreign
investors.
We depend on our senior management. Our success is largely dependent on the
skills, experience and efforts of our senior management. The loss of the
services of one or more members of our senior management could have a negative
effect on our business and development.
Seismic disturbances could damage our project. Areas where we operate and
are developing many of our geothermal and gas-fired projects are subject to
frequent low-level seismic disturbances. More significant seismic disturbances
are possible. Our existing power generation facilities are built to withstand
relatively significant levels of seismic disturbances, and we believe we
maintain adequate insurance protection. However, earthquake, property damage or
business interruption insurance may be inadequate to
25
<PAGE>
cover all potential losses sustained in the event of serious seismic
disturbances. Additionally, insurance may not continue to be available to us on
commercially reasonable terms.
Our results are subject to quarterly and seasonal fluctuations. Our
quarterly operating results have fluctuated in the past and may continue to do
so in the future as a result of a number of factors, including:
* the timing and size of acquisitions,
* the completion of development projects, and
* variations in levels of production.
Additionally, because we receive the majority of capacity payments under
some of our power sales agreements during the months of May through October, our
revenues and results of operations are, to some extent, seasonal.
The price of our common stock is volatile. The market price for our common
stock has been volatile in the past, and several factors could cause the price
to fluctuate substantially in the future. These factors include:
* announcements of developments related to our business,
* fluctuations in our results of operations,
* sales of substantial amounts of our securities into the marketplace,
* general conditions in our industry or the worldwide economy,
* an outbreak of war or hostilities,
* a shortfall in revenues or earnings compared to securities analysts'
expectations,
* changes in analysts' recommendations or projections, and
announcements of new acquisitions or development projects by us.
The market price of our common stock may fluctuate significantly in the
future, and these fluctuations may be unrelated to our performance. General
market price declines or market volatility in the future could adversely affect
the price of our common stock, and thus, the current market price may not be
indicative of future market prices.
Financial Market Risks
From time to time, we use interest rate swap agreements to mitigate our
exposure to interest rate fluctuations. We do not use derivative financial
instruments for speculative or trading purposes. The following table summarizes
the fair market value of our existing interest rate swap agreements as of June
30, 1999 (in thousands):
Weighted
Notional Average Fair
Maturity Principal Interest Market
Date Amount Rate Value
--------- --------- -------- --------
2000 $ 21,800 9.9% $ (571)
2009 65,000 6.1% 1,156
2013 75,000 7.2% (3,480)
2014 79,970 6.7% (1,423)
-------- --------- -------- --------
Total $ 241,770 7.1% $ (4,318)
========= ======== ========
Short-term investments. As of June 30, 1999, we have short-term investments
of $271.3 million. These short-term investments consist of highly liquid
investments with maturities between three and twelve months. These investments
are subject to interest rate risk and will increase in value if market interest
rates increase. We have the ability to hold these investments to maturity, and
as a result, we would not expect the value of these investments to be affected
to any significant degree by the effect of a sudden change in market interest
rates. Declines in interest rates over time will reduce our interest income.
Outstanding debt. As of June 30, 1999, we have outstanding long-term debt
of approximately $1.6 billion primarily made up of $1.5 billion of senior notes
and $79.2 million of construction financing. Our
26
<PAGE>
construction financing has a floating interest rate which has averaged 6.8%. Our
outstanding long-term Senior Notes as of June 30, 1999 are as follows (in
thousands):
Carrying Fair
Maturity Date Amount Interest Rate Market Value
------------- ----------- ------------- ------------
2004 $ 105,000 9-1/4% $ 106,050
2006 171,750 10-1/2% 185,267
2006 250,000 7-5/8% 243,125
2007 275,000 8-3/4% 282,219
2008 400,000 7-7/8% 384,600
2009 350,000 7-3/4% 330,313
------------- ----------- ------------
Total $ 1,551,750 $ 1,513,574
=========== ============
Gas prices fluctuations. We enter into derivative commodity instruments to
hedge our exposure to the impact of price fluctuations on gas purchases. Such
instruments include regulated natural gas contracts and over-the-counter swaps
and basis hedges with major energy derivative product specialists. All hedge
transactions are subject to our risk management policy which does not permit
speculative positions. These transactions are accounted for under the hedge
method of accounting. Cash flows from derivative instruments are recognized as
incurred through changes in working capital.
Impact of Recent Accounting Pronouncements -- In May 1999, the FASB issued
an Exposure Draft entitled "Deferral of the Effective Date of FASB Statement No.
133." The Exposure Draft would amend SFAS. No. 133 to defer its effective date
to all fiscal quarters of all fiscal years beginning after June 15, 2000. The
Company has not yet analyzed the impact of adopting SFAS No. 133 on the
financial statements and has not determined the timing of or method of the
adoption of SFAS No. 133. However, this Statement could increase volatility in
earnings.
Year 2000 Compliance -- The "Year 2000 Problem" refers to the fact that
some computer hardware, software and embedded systems were designed to read and
store dates using only the last two digits of the year.
We are coordinating our efforts to address the impact of Year 2000 on our
business through a Year 2000 Project Team comprised of representatives from each
business unit and our Year 2000 project office. The Year 2000 project office is
charged with addressing additional Year 2000 related issues including, but not
limited to, business continuation and other contingency planning. The Year 2000
Project Team meets regularly to monitor the efforts of assigned staff and
contractors to identify, remediate and test our technology.
The Year 2000 Project Team is focusing on four separate technology domains:
* Corporate applications, which include core business systems;
* Non-Information technology, which includes all operating and control
systems;
* End-User computing systems (that is, systems that are not, considered core
business systems but may contain date calculations); and
* Business partner and vendor systems.
Corporate Applications - Corporate applications are those major core
systems, such as customer information, human resources and general ledger, for
which our Management Information Systems department has the responsibility. We
utilize PeopleSoft for our major core systems. The PeopleSoft applications are
in operation and have been determined to be Year 2000 compliant.
Non-Information Technology/Embedded Systems - Non-information technology
includes such items as power plant operating and control systems,
telecommunications and facilities-based equipment and other embedded systems.
Each business unit is responsible for the inventory and remediation of its
embedded systems. In addition, we are working with the Electric Power Research
Institute, a consortium of power companies, including investor-owned utilities,
to coordinate vendor contacts and product evaluation. Because many embedded
systems are similar across utilities, this concentrated effort should help to
reduce
27
<PAGE>
total time expended in this area and help to ensure that the Company's efforts
are consistent with the efforts and practices of other power companies and
utilities.
An Inventory phase for non-information technology/embedded systems was
completed in October 1998. The Initial Assessment Phase was completed in
December 1998. We plan to complete remediation of non-compliant systems by the
fall of 1999. To date, all embedded systems that have been identified by Calpine
can be upgraded or modified within our current schedule. The schedule for
addressing year 2000 issues with respect to mission critical embedded systems is
as follows:
PHASE STATUS ESTIMATED COMPLETION DATE
-------------------- ---------------- -------------------------
Inventory Complete September 1998
Initial Assessment Complete November 1998
Detail Assessment Complete May 1999
Remediation In-progress (98%) July 1999 - Sept 1999
Contingency Planning In-progress (5%) August 1999 - Nov 1999
Testing of embedded systems is complex because some of the testing must be
completed during power plant scheduled maintenance outages. Most of the testing
will be accomplished in the fall of 1999 during regularly scheduled maintenance
outage periods. At that time, at least one typical unit of each critical type
will be tested by Calpine or in cooperation with other power companies, and the
requirement for further testing will be determined.
End-User Computing Systems - Some of our business units have developed
systems, databases, spreadsheets, etc. that contain date calculations.
Compliance of individual workstations is also included in this domain. These
systems comprise a relatively small percentage of the required modification in
terms of both number and criticality.
Our end-user computing systems are being inventoried by each business unit
and evaluated and remediated by the Company's MIS staff. We expect to complete
remediation and testing of the end-user computing systems by mid-1999.
Business Partner and Vendor Systems - We have contracts with business
partners and vendors who provide products and services to the Company. We are
vigorously seeking to obtain Year 2000 assurances from these third parties. Year
2000 Project Team and appropriate business units are jointly undertaking this
effort. We have sent letters and accompanying Year 2000 surveys to about 800
vendors and suppliers. Over 600 responses have been received as of July 1999.
These responses outline to varying degrees the approaches vendors are
undertaking to resolve Year 2000 issues within their own systems. Follow-up
letters are being sent to those vendors who have not responded or whose
responses were inadequate.
Contingency Planning - Contingency and business continuation planning are
in various stages of development for critical and high-priority systems. Our
existing disaster response plan and other contingency plans are scheduled to be
evaluated and will be adopted for use in case of any Year 2000 related
disruption. We expect to complete our contingency planning by November 1999.
Costs - The costs of expected modifications are currently estimated to be
approximately $1.7 million which will be charged to expense as incurred. From
January 1, 1998 through June 30, 1999, $321,000 has been charged to expense.
Approximately 9% of the estimated total cost has been incurred in 1998, 63% will
be incurred in 1999, and the remainder will be incurred in 2000. These costs
have been and will be funded through operating cash flow. These estimates may
change as additional evaluations are completed and remediation and testing
progress.
Risks - We currently expect to complete our Year 2000 efforts with respect
to critical systems by fall of 1999. This schedule and our cost estimates may be
affected by, among other things, the availability of Year 2000 personnel, the
readiness of third parties, the timing for testing our embedded systems, the
availability of vendor resources to complete embedded system assessments and
produce required component upgrades and our ability to implement appropriate
contingency plans.
28
<PAGE>
We produce revenues by selling power we produce to customers. We depend on
transmission and distribution facilities that are owned and operated by
investor-owned utilities to deliver power to the our customers. If either our
customers or the providers of transmission and distribution facilities
experience significant disruptions as a result of the Year 2000 problem, our
ability to sell and deliver power may be hindered, which could result in a loss
of revenue.
The cost or consequences of a materially incomplete or untimely resolution
of the Year 2000 problem could adversely affect our future operations, financial
results or our financial condition.
The forward-looking statements discussed in this outlook section involve a
number of risks and uncertainties. Other risks and uncertainties include, but
are not limited to, the general economy, regulatory conditions, the changing
environment of the power generation industry, pricing, the effects of legal and
administrative cases and proceedings, and such other risks and uncertainties as
may be detailed from time to time in our SEC reports and filings.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On September 30, 1997, a lawsuit was filed by Indeck North American Power Fund
("Indeck") in the Circuit Court of Cook County, Illinois against Norweb plc. and
certain other parties, including the Company. Some of Indeck's claims relate to
Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville
Energy L.P. from Northern Hydro Limited and Calpine Auburndale, Inc.'s
acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck claimed that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortuously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. In April 1999, the court granted Calpine Gordonsville
and Calpine Auburndale's motions to dismiss with prejudice, a decision which has
been appealed by Indeck. The Company is unable to predict the outcome of these
proceedings.
There is currently a dispute between Texas-New Mexico Power Company ("TNP") and
Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear Lake
Power Plant, regarding certain costs and other amounts that TNP has withheld
from payments due under the power sales agreement from August 1997 until October
1998. TNP has withheld approximately $450,000 per month related to transmission
charges. In October 1997, CLC filed a petition for declaratory order with the
Texas Public Utilities Commission ("Texas PUC") requesting a declaration that
TNP's withholding is in error, which petition is currently pending. Also, as of
June 30, 1999, TNP has withheld approximately $7.7 million of standby power
charges. In addition to the Texas PUC petition, CLC filed an action in Texas
courts on October 2, 1997, alleging TNP's breach of the power sales agreement
and is seeking refund of the standby charges. Both the Texas PUC action and the
court action have been put on hold pending completion of a settlement. A final
order was issued by the Texas PUC on July 15, 1999, approving the settlement
documentation which includes an $8.0 million cash payment by TNP to CLC.
An action was filed against Lockport Energy Associates, L.P. ("LEA") and the New
York Public Service Commission ("NYPSC") in August 1997 by New York State
Electricity and Gas Company ("NYSEG") in the Federal District Court for the
Northern District of New York. NYSEG has requested the Court to direct NYPSC and
the Federal Energy Regulatory Commission (the "FERC") to modify contract rates
to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a
cross-claim alleging that the FERC violated the Public Utility Regulatory
Policies Act of 1978 as amended, ("PURPA") and the Federal Power Act by failing
to reform the NYSEG contract that was previously approved by the NYPSC. Although
it is unable to predict the outcome of this case, in any event, the Company
retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase
the Company's interest in the Lockport Power Plant for $18.9 million, less
equity distributions received by the Company, at any time before December 19,
2001.
29
<PAGE>
The Company is involved in various other claims and legal actions arising out of
the normal course of business. The Company does not expect that the outcome of
these proceedings will have a material adverse effect on the Company's financial
position or results of operations, although no assurance can be given in this
regard.
ITEM 2. CHANGE IN SECURITIES
None.
ITEM 3. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Reference is made to Part II, Item 7A, Quantitative and Qualitative Disclosures
About Market Risk, in the Company's Annual Report on Form 10-K for the year
ended December 31, 1998 and to the subheading "Financial Market Risks" under the
heading "Management's Discussion and Analysis of Financial Condition and Results
of Operations" on pages 35-36 of the Company's Annual Report on Form 10-K for
the year ended December 31, 1998.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Our Annual Meeting of Stockholders was held on May 27, 1999 (the "Annual
Meeting") in San Jose, California. At the Annual Meeting, stockholders voted on
two matters: (i) the election of two Class II directors for a term of three
years expiring in 2002 and (ii) the ratification of the appointment of Arthur
Andersen L.L.P. as independent auditors for Calpine for the year ending December
31, 1999. The stockholders elected management's nominees as the Class II
directors in an uncontested election and ratified the appointment of independent
auditors by the following votes, respectively:
(i) Election of Class II directors for a three year term expiring in 2002
for Peter Cartwright and Susan C. Schwab, 20,037,508
FOR and 517,047 ABSTAIN,
(ii) Election of Arthur Andersen L.L.P. as independent auditors for the year
ending December 31, 1999, 20,544,967 FOR, 3,060
AGAINST, and 5,528 ABSTAIN.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Reports on Form 8-K
Current report dated May 7, 1999 and filed on May 21, 1999
Item 5. Other Events -- Announcement of the Acquisition of PG&E Power
Plants
Item 7. Exhibits -- Press release dated May 10, 1999
(b) Exhibits
The following exhibits are filed herewith unless otherwise indicated:
Exhibit
Number Description
- ------- ------------------------------------------------------------
3.1 --Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(b)
3.2 --Amended and Restated Bylaws of Calpine Corporation, a
Delaware corporation.(b)
4.1 --Indenture dated as of February 17, 1994 between the Company and
Shawmut Bank of
30
<PAGE>
Connecticut, National Association, as Trustee, including form of
Notes.(a)
4.2 --Indenture dated as of May 16, 1996 between the Company and Fleet
National Bank, as Trustee, including form of Notes.(c)
4.3 --Indenture dated as of July 8, 1997 between the Company and The Bank
of New York, as Trustee, including form of Notes.(e)
4.4 --Indenture dated as of March 31, 1998 between the Company and The Bank
of New York, as Trustee, including form of Notes.(h)
4.5 --Indenture dated as of March 26, 1999 between the Company and The Bank
of New York, as Trustee, including form of Notes.(I)
4.6 --Indenture dated as of April 21, 1999 between the Company and The Bank
of New York, as Trustee, including form of Notes.(I)
10.1 --Purchase Agreements
10.1.1 --Purchase and Sale Agreement dated March 27, 1997 for the purchase and
sale of shares of Enron/Dominion Cogen Corp. Common Stock among Enron
Power Corporation and Calpine Corporation.(f)
10.1.2 --Stock Purchase and Redemption Agreement dated March 31, 1998, among
Dominion Cogen, Inc. Dominion Energy, Inc. and Calpine Finance.(f)
10.1.3 --Stock Purchase Agreement dated May 1, 1998 and between Calpine
Corporation and CCNG Investments, L.P.(g)
10.2 --Power Sales Agreements
10.2.1 --Amended and Restated Energy Sales Agreement, dated December 16, 1996,
between Phillips Petroleum Company and Pasadena Cogeneration, L.P.(d)
10.3 --Other Agreements
10.3.1 --Calpine Corporation Stock Option Program and forms of agreements
thereunder.(a)
10.3.2 --Calpine Corporation 1996 Stock Incentive Plan and forms of agreements
thereunder.(b)
10.3.3 --Calpine Corporation Employee Stock Purchase Plan and forms of
agreements thereunder.(b)
10.3.4 --Amended and Restated Employment Agreement between Calpine Corporation
and Mr. Peter Cartwright.(b)
10.3.5 --Executive Vice President Employment Agreement between Calpine
Corporation and Ms. Ann B. Curtis.(b)
10.3.6 --Executive Vice President Employment Agreement between Calpine
Corporation and Mr. Lynn A. Kerby.(b)
10.3.7 --Vice President Employment Agreement between Calpine Corporation and Mr.
Ron A. Walter.(b)
10.3.8 --Vice President Employment Agreement between Calpine Corporation and Mr.
Robert D. Kelly.(b)
10.3.9 --First Amended and Restated Consulting Contract between Calpine
Corporation and Mr. George J. Stathakis.(b)
10.4 --Form of Indemnification Agreement for directors and officers.(b)
21.1 --Subsidiaries of the Company.(c)
27.0 --Financial Data Schedule.*
___________
(a) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 33-73160).
31
<PAGE>
(b) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 333-07497).
(c) Incorporated by reference to Registrant's Current Report on Form 8-K dated
August 29, 1996 and filed on September 13, 1996.
(d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1996, filed on March 27, 1996.
(e) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1997 and filed on August 14, 1997.
(f) Incorporated by reference to Registrant's Current Report on Form 8-K dated
March 31, 1998 and filed on April 14, 1998.
(g) Incorporated by reference to Registrant's Current Report on Form 8-K dated
May 26, 1998 and filed on June 9, 1998.
(h) Incorporated by reference to Registrant's Registration Statement on Form
S-4, filed on August 10, 1998 (Registration Statement No. 333-61047).
(i) Incorporated by reference to Registrant's Form 424B filed on March 26, 1999
with the Securities and Exchange Commission.
* Filed herewith.
Exhibit 27 Financial Data Schedule
32
<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: August 12, 1999
---------------------------------
Ann B. Curtis
Executive Vice President
(Chief Financial Officer)
By: /s/ Charles B. Clark, Jr. Date: August 12, 1999
----------------------------------
Charles B. Clark, Jr.
Vice President and Corporate Controller
(Chief Accounting Officer)
33
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CALPINE
CORPORATION'S CONSOLIDATED BALANCE SHEET AS OF JUNE 30, 1999 AND FROM THE
CONSOLIDATED STATEMENT OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 1999 AND
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH STATEMENTS.
</LEGEND>
<CIK> 0000916457
<NAME> CALPINE CORPORATION
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLAR
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<EXCHANGE-RATE> 1
<CASH> 320,287
<SECURITIES> 0
<RECEIVABLES> 118,590
<ALLOWANCES> 0
<INVENTORY> 14,504
<CURRENT-ASSETS> 473,809
<PP&E> 1,568,882
<DEPRECIATION> 231,605
<TOTAL-ASSETS> 2,549,750
<CURRENT-LIABILITIES> 127,380
<BONDS> 0
0
0
<COMMON> 27
<OTHER-SE> 514,100
<TOTAL-LIABILITY-AND-EQUITY> 2,549,750
<SALES> 304,322
<TOTAL-REVENUES> 336,590
<CGS> 226,709
<TOTAL-COSTS> 238,170
<OTHER-EXPENSES> 25,212
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 47,171
<INCOME-PRETAX> 37,105
<INCOME-TAX> 14,545
<INCOME-CONTINUING> 22,560
<DISCONTINUED> 0
<EXTRAORDINARY> 1,150
<CHANGES> 0
<NET-INCOME> 21,410
<EPS-BASIC> 0.90
<EPS-DILUTED> 0.85
</TABLE>
