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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
---------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
OR
[ ] 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: 1-12079
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 by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date:
443,828,145 shares of Common Stock, par value $.001 per share, outstanding
on August 6, 2004.
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CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended June 30, 2004
INDEX
Page No.
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PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Condensed Balance Sheets June 30, 2004 and December 31, 2003..................... 3
Consolidated Condensed Statements of Operations for the Three and Six Months Ended
June 30, 2004 and 2003...................................................................... 5
Consolidated Condensed Statements of Cash Flows for the Six Months Ended
June 30, 2004 and 2003...................................................................... 7
Notes to Consolidated Condensed Financial Statements.......................................... 9
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations............ 38
Item 3. Quantitative and Qualitative Disclosures About Market Risk....................................... 71
Item 4. Controls and Procedures.......................................................................... 71
PART II - OTHER INFORMATION
Item 1. Legal Proceedings................................................................................ 72
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities................. 77
Item 4. Submission of Matters to a Vote of Security Holders.............................................. 78
Item 6. Exhibits and Reports on Form 8-K................................................................. 79
Signatures...................................................................................................... 81
-2-
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
June 30, 2004 and December 31, 2003
(in thousands, except share and per share amounts)
June 30, December 31,
2004 2003
-------------- --------------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents....................................................... $ 844,031 $ 991,806
Accounts receivable, net........................................................ 1,170,130 988,947
Margin deposits and other prepaid expense....................................... 406,741 385,348
Inventories..................................................................... 144,913 139,654
Restricted cash................................................................. 317,833 383,788
Current derivative assets....................................................... 338,805 496,967
Current assets held for sale.................................................... -- 651
Other current assets............................................................ 72,117 89,593
-------------- --------------
Total current assets......................................................... 3,294,570 3,476,754
-------------- --------------
Restricted cash, net of current portion............................................ 191,695 575,027
Notes receivable, net of current portion........................................... 225,396 213,629
Project development costs.......................................................... 151,084 139,953
Investments in power projects and oil and gas properties........................... 417,303 472,749
Deferred financing costs........................................................... 423,499 400,732
Prepaid lease, net of current portion.............................................. 383,940 414,058
Property, plant and equipment, net................................................. 21,031,174 20,081,052
Goodwill, net...................................................................... 45,160 45,160
Other intangible assets, net....................................................... 89,411 89,924
Long-term derivative assets........................................................ 561,328 673,979
Long-term assets held for sale..................................................... -- 112,148
Other assets....................................................................... 627,202 608,767
-------------- --------------
Total assets............................................................... $ 27,441,762 $ 27,303,932
============== ==============
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable................................................................ $ 1,160,600 $ 938,644
Accrued payroll and related expense............................................. 72,644 96,693
Accrued interest payable........................................................ 362,497 321,176
Income taxes payable............................................................ 5,680 18,026
Notes payable and borrowings under lines of credit, current portion............. 239,289 254,292
Preferred interests, current portion............................................ 8,758 11,220
Capital lease obligation, current portion....................................... 8,466 4,008
CCFC I financing, current portion............................................... 3,208 3,208
Construction/project financing, current portion................................. 57,256 61,900
Senior notes and term loans, current portion.................................... 14,500 14,500
Current derivative liabilities.................................................. 383,097 456,688
Other current liabilities....................................................... 271,589 335,048
-------------- --------------
Total current liabilities.................................................... 2,587,584 2,515,403
-------------- --------------
Notes payable and borrowings under lines of credit, net of current portion......... 861,424 873,572
Notes payable to Calpine Capital Trusts............................................ 1,153,500 1,153,500
Preferred interests, net of current portion........................................ 142,064 232,412
Capital lease obligation, net of current portion................................... 283,005 193,741
CCFC I financing, net of current portion........................................... 784,661 785,781
CalGen/CCFC II financing........................................................... 2,448,907 2,200,358
Construction/project financing, net of current portion............................. 1,723,040 1,209,505
Convertible Senior Notes Due 2006.................................................. 72,126 660,059
Convertible Senior Notes Due 2023.................................................. 900,000 650,000
Senior notes and term loans, net of current portion................................ 9,370,936 9,369,253
Deferred income taxes, net......................................................... 1,185,712 1,310,335
Deferred lease incentive........................................................... -- 50,228
Deferred revenue................................................................... 110,087 116,001
Long-term derivative liabilities................................................... 599,495 692,088
Long-term liabilities held for sale................................................ -- 161
Other liabilities.................................................................. 267,769 259,390
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Total liabilities.......................................................... 22,490,310 22,271,787
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Minority interests................................................................. 350,561 410,892
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-3-
June 30, December 31,
2004 2003
-------------- --------------
(Unaudited)
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 10,000,000 shares;
none issued and outstanding in 2004 and 2003................................... -- --
Common stock, $.001 par value per share; authorized 1,000,000,000 shares
at December 31, 2003, and 2,000,000,000 shares at June 30, 2004;
issued and outstanding 439,326,249 shares in 2004 and
415,010,125 shares in 2003..................................................... 439 415
Additional paid-in capital...................................................... 3,109,778 2,995,735
Retained earnings............................................................... 1,468,619 1,568,509
Accumulated other comprehensive income.......................................... 22,055 56,594
-------------- --------------
Total stockholders' equity.............................................. $ 4,600,891 $ 4,621,253
-------------- --------------
Total liabilities and stockholders' equity.............................. $ 27,441,762 $ 27,303,932
============== ==============
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
-4-
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2004 and 2003
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
(In thousands, except
per share amounts)
(Unaudited)
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue.......................... $ 1,312,792 $ 1,046,260 $ 2,558,678 $ 2,146,328
Sales of purchased power for hedging and optimization.. 496,652 744,805 876,680 1,426,089
------------ ------------ ------------ ------------
Total electric generation and marketing revenue...... 1,809,444 1,791,065 3,435,358 3,572,417
Oil and gas production and marketing revenue
Oil and gas sales...................................... 26,069 29,299 50,651 55,210
Sales of purchased gas for hedging and optimization.... 481,971 328,478 834,708 655,945
------------ ------------ ------------ ------------
Total oil and gas production and marketing revenue... 508,040 357,777 885,359 711,155
Mark-to-market activities, net............................ (22,605) 1,839 (10,086) 22,282
Other revenue............................................. 19,755 14,627 46,741 25,386
------------ ------------ ------------ ------------
Total revenue..................................... 2,314,634 2,165,308 4,357,372 4,331,240
------------ ------------ ------------ ------------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense................................ 223,664 159,646 399,498 321,574
Transmission purchase expense.......................... 14,651 11,330 31,078 20,156
Royalty expense........................................ 6,951 6,461 12,833 11,818
Purchased power expense for hedging and optimization... 445,169 738,719 820,108 1,418,668
------------ ------------ ------------ ------------
Total electric generation and marketing expense...... 690,435 916,156 1,263,517 1,772,216
Oil and gas operating and marketing expense
Oil and gas operating expense.......................... 23,443 29,033 45,770 54,694
Purchased gas expense for hedging and optimization..... 453,922 331,122 814,409 648,070
------------ ------------ ------------ ------------
Total oil and gas operating and marketing expense.... 477,365 360,155 860,179 702,764
Fuel expense.............................................. 867,785 539,409 1,630,490 1,174,778
Depreciation, depletion and amortization expense.......... 161,789 138,957 311,203 272,771
Operating lease expense................................... 26,963 28,168 54,762 55,860
Other cost of revenue..................................... 22,607 6,870 48,988 12,121
------------ ------------ ------------ ------------
Total cost of revenue............................. 2,246,944 1,989,715 4,169,139 3,990,510
------------ ------------ ------------ ------------
Gross profit................................... 67,690 175,593 188,233 340,730
Loss (income) from unconsolidated investments in power
projects and oil and gas properties......................... 718 (59,351) (1,788) (64,475)
Equipment cancellation and impairment cost................... 7 19,222 2,367 19,309
Project development expense.................................. 4,030 6,072 11,748 11,158
Research and development expense............................. 5,124 2,469 8,939 4,860
Sales, general and administrative expense.................... 60,978 53,710 118,225 97,367
------------ ------------ ------------ ------------
Income (loss) from operations............................. (3,167) 153,471 48,742 272,511
Interest expense............................................. 279,659 148,879 534,452 291,840
Distributions on trust preferred securities.................. -- 15,656 -- 31,313
Interest (income)............................................ (9,920) (9,003) (21,981) (17,037)
Minority interest expense.................................... 4,724 5,335 13,159 7,612
(Income) from repurchase of various issuances of debt........ (2,559) (6,763) (3,394) (6,763)
Other expense (income)....................................... (185,571) 20,467 (203,996) 55,056
------------ ------------ ------------ ------------
Loss before (benefit) for income taxes.................... (89,500) (21,100) (269,498) (89,510)
(Benefit) for income taxes................................... (60,604) (4,725) (146,553) (21,596)
------------ ------------ ------------ ------------
Loss before discontinued operations and cumulative
effect of a change in accounting principle............... (28,896) (16,375) (122,945) (67,914)
Discontinued operations, net of tax provision (benefit)
of $126, $(4,484), $12,452, and $(5,275).................... 198 (6,991) 23,055 (7,997)
Cumulative effect of a change in accounting principle,
net of tax provision of $--, $--, $--and $450............... -- -- -- 529
------------ ------------ ------------ ------------
Net loss....................................... $ (28,698) $ (23,366) $ (99,890) $ (75,382)
============ ============ ============ ============
-5-
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
(In thousands, except
per share amounts)
(Unaudited)
Basic and diluted loss per common share:
Weighted average shares of common stock outstanding....... 417,357 381,219 416,332 381,089
Loss before discontinued operations and cumulative
effect of a change in accounting principle............... $ (0.07) $ (0.04) $ (0.30) $ (0.18)
Discontinued operations, net of tax....................... $ -- $ (0.02) $ 0.06 $ (0.02)
Cumulative affect of a change in accounting principle,
net of tax............................................... $ -- $ -- $ -- $ --
------------ ------------ ------------ ------------
Net loss....................................... $ (0.07) $ (0.06) $ (0.24) $ (0.20)
============ ============ ============ ============
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
-6-
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2004 and 2003
(in thousands)
(unaudited)
Six Months Ended
June 30,
------------------------------
2004 2003
-------------- --------------
Cash flows from operating activities:
Net loss......................................................................... $ (99,890) $ (75,382)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depreciation, depletion and amortization (1)................................ 397,143 325,112
Deferred income taxes, net.................................................. (147,898) 101,802
(Gain) loss on sale of assets and development cost write-offs, net.......... (105,495) 9,367
Stock compensation expense.................................................. 9,766 8,423
Foreign exchange (gains) losses............................................. (4,832) 44,304
Change in net derivative assets and liabilities............................. (9,541) 33,099
Income from unconsolidated investments in power projects
and oil and gas properties................................................. (1,788) (64,475)
Distributions from unconsolidated investments in power projects............. 14,697 121,015
Other....................................................................... 9,765 18,351
Change in operating assets and liabilities, net of effects of
acquisitions:
Accounts receivable......................................................... (176,433) (191,717)
Other current assets........................................................ 9,796 (145,349)
Other assets................................................................ (36,222) (58,536)
Accounts payable and accrued expense........................................ 235,725 (34,659)
Other liabilities........................................................... (82,800) 21,949
-------------- --------------
Net cash provided by operating activities................................ 11,993 113,304
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Cash flows from investing activities:
Purchases of property, plant and equipment....................................... (795,403) (1,135,549)
Disposals of property, plant and equipment....................................... 257,635 13,681
Acquisitions, net of cash acquired............................................... (187,614) (6,818)
Advances to joint ventures....................................................... (4,088) (49,683)
Project development costs........................................................ (16,324) (20,513)
Sale of collateral securities.................................................... 93,963 --
Decrease (increase) in restricted cash........................................... 452,377 (122,623)
Decrease (increase) in notes receivable.......................................... 6,012 (5,794)
Other............................................................................ 26,051 29,496
-------------- --------------
Net cash used in investing activities.................................... (167,391) (1,297,803)
-------------- --------------
Cash flows from financing activities:
Borrowings from notes payable and borrowings under lines of credit............... 2,643,578 1,095,384
Repayments of notes payable and borrowings under lines of credit................. (2,520,059) (15,269)
Borrowings from project financing................................................ 924,475 77,013
Repayments of project financing.................................................. (596,887) (143,998)
Repayments of Senior Notes....................................................... (56,219) (16,100)
Repurchase of 4% Convertible Senior Notes........................................ (586,926) --
Proceeds from issuance of 4.75% Convertible Senior Notes......................... 250,000 --
Proceeds from issuance of Senior Notes........................................... 100,000 --
Proceeds from income trust offering.............................................. -- 126,462
Financing costs.................................................................. (124,089) (134,443)
Other............................................................................ (13,104) 28,265
-------------- --------------
Net cash provided by financing activities................................ 20,769 1,017,314
-------------- --------------
Effect of exchange rate changes on cash and cash equivalents........................ (13,146) 5,653
Net decrease in cash and cash equivalents........................................... (147,775) (161,532)
Cash and cash equivalents, beginning of period...................................... 991,806 579,486
-------------- --------------
Cash and cash equivalents, end of period............................................ $ 844,031 $ 417,954
============== ==============
Cash paid during the period for:
Interest, net of amounts capitalized............................................. $ 399,736 $ 217,543
Income taxes..................................................................... $ 21,621 $ 10,789
- ------------
<FN>
(1) Includes depreciation and amortization that is charged to cost of revenue
and also included within sales, general and administrative expense and to
interest expense in the Consolidated Condensed Statements of Operations.
</FN>
-7-
Schedule of noncash investing and financing activities:
2004 issuance of 20.1 million shares of common stock in exchange for
$20.0 million par value of HIGH TIDES I and $75.0 million par value of
HIGH TIDES II.
2004 Capital lease entered into for the King City facility. See Note 6
of the Notes to Consolidated Condensed Financial Statements for
further discussion.
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
-8-
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
June 30, 2004
(unaudited)
1. Organization and Operations of the Company
Calpine Corporation ("Calpine" or "the Company"), a Delaware corporation,
and subsidiaries (collectively, also referred to as the "Company") are engaged
in the generation of electricity in the United States of America, Canada, Mexico
and the United Kingdom. The Company is involved in the development,
construction, ownership and operation of power generation facilities and the
sale of electricity and its by-product, thermal energy, primarily in the form of
steam. The Company has ownership interests in, and operates, gas-fired power
generation and cogeneration facilities, gas fields, gathering systems and gas
pipelines, geothermal steam fields and geothermal power generation facilities in
the United States of America. In Canada, the Company owns oil and gas operations
and has ownership interests in, and operates, gas-fired power generation
facilities. In Mexico, Calpine is a joint venture participant in a gas-fired
power generation facility under construction. In the United Kingdom, the Company
owns and operates a gas-fired power cogeneration facility. Each of the
generation facilities produces and markets electricity for sale to utilities and
other third party purchasers. Thermal energy produced by the gas-fired power
cogeneration facilities is primarily sold to industrial users. Gas produced, and
not physically delivered to the Company's generating plants, is sold to third
parties.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying unaudited interim
Consolidated Condensed Financial Statements of the Company have been prepared by
the Company pursuant to the rules and regulations of the Securities and Exchange
Commission. In the opinion of management, the Consolidated Condensed 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 in the United States of America have been
condensed or omitted from these statements pursuant to such rules and
regulations and, accordingly, these financial statements should be read in
conjunction with the audited Consolidated Financial Statements of the Company
for the year ended December 31, 2003, included in the Company's Annual Report on
Form 10-K. The results for interim periods are not necessarily indicative of the
results for the entire year.
Reclassifications -- Certain prior years' amounts in the Consolidated
Financial Statements have been reclassified to conform to the 2004 presentation
including reclassification of transmission revenues from electricity and sales
revenue to other revenue..
Use of Estimates in Preparation of Financial Statements -- The preparation
of financial statements in conformity with generally accepted accounting
principles in the United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expense during the reporting
period. Actual results could differ from those estimates. The most significant
estimates with regard to these financial statements relate to useful lives and
carrying values of assets (including the carrying value of projects in
development, construction retirement and operation), provision for income taxes,
fair value calculations of derivative instruments and associated reserves,
capitalization of interest, primary beneficiary determination for the Company's
investments in variable interest entities, the outcome of pending litigation and
estimates of oil and gas reserves used to calculate depletion, depreciation and
impairment of natural gas and petroleum property and equipment.
Effective Tax Rate -- For the three months ended June 30, 2004 and 2003,
the effective rate was 68% and 22%, respectively. For the six months ended June
30, 2004 and 2003, the effective rate was 54% and 24%, respectively. This
effective rate variance is due to the consideration of estimated year-end
earnings in estimating the quarterly effective rate and due to the effect of
significant permanent items.
Derivative Instruments -- Financial Accounting Standards Board ("FASB")
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS No. 133") as amended and
interpreted by other related accounting literature, establishes accounting and
reporting standards for derivative instruments (including certain derivative
instruments embedded in other contracts). SFAS No. 133 requires companies to
record derivatives on their balance sheets as either assets or liabilities
measured at their fair value unless exempted from derivative treatment as a
normal purchase and sale. All changes in the fair value of derivatives are
recognized currently in earnings unless specific hedge criteria are met, which
requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting.
-9-
Accounting for derivatives at fair value requires the Company to make
estimates about future prices during periods for which price quotes are not
available from sources external to the Company. As a result, the Company is
required to rely on internally developed price estimates when external price
quotes are unavailable. The Company derives its future price estimates, during
periods where external price quotes are unavailable, based on an extrapolation
of prices from periods where external price quotes are available. The Company
performs this extrapolation using liquid and observable market prices and
extending those prices to an internally generated long-term price forecast based
on a generalized equilibrium model.
SFAS No. 133 sets forth the accounting requirements for cash flow and fair
value hedges. SFAS No. 133 provides that the effective portion of the gain or
loss on a derivative instrument designated and qualifying as a cash flow hedging
instrument be reported as a component of other comprehensive income and be
reclassified into earnings in the same period during which the hedged forecasted
transaction affects earnings. The remaining gain or loss on the derivative
instrument, if any, must be recognized currently in earnings. SFAS No. 133
provides that the changes in fair value of derivatives designated as fair value
hedges and the corresponding changes in the fair value of the hedged risk
attributable to a recognized asset, liability, or unrecognized firm commitment
be recorded in earnings. If the fair value hedge is effective, the amounts
recorded will offset in earnings.
With respect to cash flow hedges, if the forecasted transaction is no
longer probable of occurring, the associated gain or loss recorded in other
comprehensive income is recognized currently. In the case of fair value hedges,
if the underlying asset, liability or firm commitment being hedged is disposed
of or otherwise terminated, the gain or loss associated with the underlying
hedged item is recognized currently. If the hedging instrument is terminated
prior to the occurrence of the hedged forecasted transaction for cash flow
hedges, or prior to the settlement of the hedged asset, liability or firm
commitment for fair value hedges, the gain or loss associated with the hedge
instrument remains deferred.
Where the Company's derivative instruments are subject to a master netting
agreement and the criteria of FASB Interpretation ("FIN") 39 "Offsetting of
Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10
and SFAS No. 105)" are met, the Company presents its derivative assets and
liabilities on a net basis in its balance sheet. The Company has chosen this
method of presentation because it is consistent with the way related
mark-to-market gains and losses on derivatives are recorded in its Consolidated
Statements of Operations and within Other Comprehensive Income ("OCI").
Preferred Interests -- As required in SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity," the
Company classifies certain preferred interests that are mandatorily redeemable,
in short-term and long-term debt. These instruments require the Company to make
priority distributions of available cash, as defined in each preferred interest
agreement, representing a return of the preferred interest holder's investment
over a fixed period of time and at a specified rate of return in priority to
certain other distributions to equity holders. The return on investment is
recorded as interest expense under the interest method over the term of the
priority period.
Mark-to-Market Activity, Net -- This includes realized settlements of and
unrealized mark-to-market gains and losses on both power and gas derivative
instruments not designated as cash flow hedges, including those held for trading
purposes. Gains and losses due to ineffectiveness on hedging instruments are
also included in unrealized mark-to-market gains and losses. Trading activity is
presented net in accordance with Emerging Issues Task Force ("EITF") Issue No.
02-3, "Issues Related to Accounting for Contracts Involved in Energy Trading and
Risk Management Activities" ("EITF Issue No. 02-3").
Presentation of Revenue Under EITF Issue No. 03-11 "Reporting Realized
Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133 and
Not `Held for Trading Purposes' As Defined in EITF Issue No. 02-3: "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" ("EITF
Issue No. 03-11") -- The Company accounts for certain of its power sales and
purchases on a net basis under EITF Issue No. 03-11, which the Company adopted
on a prospective basis on October 1, 2003. Transactions with either of the
following characteristics are presented net in the Company's Consolidated
Condensed Financial Statements: (1) transactions executed in a back-to-back buy
and sale pair, primarily because of market protocols; and (2) physical power
purchase and sale transactions where the Company's power schedulers net the
physical flow of the power purchase against the physical flow of the power sale
(or "book out" the physical power flows) as a matter of scheduling convenience
to eliminate the need to schedule actual power delivery. These book out
transactions may occur with the same counterparty or between different
counterparties where the Company has equal but offsetting physical purchase and
delivery commitments. In accordance with EITF Issue No. 03-11, the Company
netted the following amounts (in thousands):
-10-
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
Sales of purchased power for hedging and optimization..... $ 321,954 $ -- $ 692,466 $ --
------------ ------------ ------------ ------------
Purchased power expense for hedging and optimization...... 321,954 -- 692,466 --
------------ ------------ ------------ ------------
$ -- $ -- $ -- $ --
============ ============ ============ ============
New Accounting Pronouncements
On January 1, 2003, the Company prospectively adopted the fair value method
of accounting for stock-based employee compensation pursuant to SFAS No. 123,
"Accounting for Stock-Based Compensation" ("SFAS No. 123") as amended by SFAS
No. 148, "Accounting for Stock-Based Compensation -- Transition and Disclosure"
("SFAS No. 148"). SFAS No. 148 amends SFAS No. 123 to provide alternative
methods of transition for companies that voluntarily change their accounting for
stock-based compensation from the less preferred intrinsic value based method to
the more preferred fair value based method. Prior to its amendment, SFAS No. 123
required that companies enacting a voluntary change in accounting principle from
the intrinsic value methodology provided by Accounting Principles Board ("APB")
Opinion No. 25, "Accounting for Stock Issued to Employees" could only do so on a
prospective basis; no adoption or transition provisions were established to
allow for a restatement of prior period financial statements. SFAS No. 148
provides two additional transition options to report the change in accounting
principle -- the modified prospective method and the retroactive restatement
method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS
No. 123 to require prominent disclosures in both annual and interim financial
statements about the method of accounting for stock-based employee compensation
and the effect of the method used on reported results. The Company has elected
to adopt the provisions of SFAS No. 123 on a prospective basis; consequently,
the Company is required to provide a pro-forma disclosure of net income and
earnings per share as if SFAS No. 123 accounting had been applied to all prior
periods presented within its financial statements. As shown below, the adoption
of SFAS No. 123 has had a material impact on the Company's financial statements.
The table below reflects the pro forma impact of stock-based compensation on the
Company's net loss and loss per share for the three and six months ended June
30, 2004 and 2003, had the Company applied the accounting provisions of SFAS No.
123 to its prior years' financial statements (in thousands, except per share
amounts):
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
Net loss
As reported............................................... $ (28,698) $ (23,366) $ (99,890) $ (75,382)
Pro Forma................................................. (29,974) (26,860) (102,813) (83,657)
Loss per share data:
Basic loss per share
As reported............................................ $ (0.07) $ (0.06) $ (0.24) $ (0.20)
Pro Forma.............................................. (0.07) (0.07) (0.25) (0.22)
Diluted earnings per share
As reported............................................ $ (0.07) $ (0.06) $ (0.24) $ (0.20)
Pro Forma.............................................. (0.07) (0.07) (0.25) (0.22)
Stock-based compensation cost, net of tax, included in net
loss, as reported........................................... $ 3,499 $ 2,909 $ 6,080 $ 6,276
Stock-based compensation cost, net of tax, included in net
loss, pro forma............................................. 4,775 6,403 9,003 14,551
The range of fair values of the Company's stock options granted for the
three months ended June 30, 2004 and 2003, respectively, was as follows, based
on varying historical stock option exercise patterns by different levels of
Calpine employees: $1.90-$2.91 in 2004, $2.52-$4.38 in 2003, on the date of
grant using the Black-Scholes option pricing model with the following
weighted-average assumptions: expected dividend yields of 0%, expected
volatility of 69.11%-88.07% and 70.82%-84.93% for the three months ended June
30, 2004 and 2003, respectively, risk-free interest rates of 3.18%-4.54% and
2.47%-3.40% for the three months ended June 30, 2004 and 2003, respectively, and
expected option terms of 3-8 years and 4-9 1/2 years for the three months ended
June 30, 2004 and 2003, respectively.
-11-
The range of fair values of the Company's stock options granted for the six
months ended June 30, 2004 and 2003, respectively, was as follows, based on
varying historical stock option exercise patterns by different levels of Calpine
employees: $1.90-$4.45 in 2004, $2.43-3.41 in 2003, on the date of grant using
the Black-Scholes option pricing model with the following weighted-average
assumptions: expected dividend yields of 0%, expected volatility of
69.11%-97.99% and 70.44%-112.99% for the six months ended June 30, 2004 and
2003, respectively, risk-free interest rates of 2.35%-4.54% and 1.39%-4.04% for
the six months ended June 30, 2004 and 2003, respectively, and expected option
terms of 3-9 1/2 years and 2 1/2-9 1/2 years for the six months ended June 30,
2004 and 2003, respectively.
In January 2003 FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an interpretation of ARB 51" ("FIN 46"). FIN 46
requires the consolidation of an entity by an enterprise that absorbs a majority
of the entity's expected losses, receives a majority of the entity's expected
residual returns, or both, as a result of ownership, contractual or other
financial interest in the entity. Historically, entities have generally been
consolidated by an enterprise when it has a controlling financial interest
through ownership of a majority voting interest in the entity. The objectives of
FIN 46 are to provide guidance on the identification of Variable Interest
Entities ("VIEs") for which control is achieved through means other than
ownership of a majority of the voting interest of the entity, and how to
determine which business enterprise (if any), as the Primary Beneficiary, should
consolidate the Variable Interest Entity ("VIE"). This new model for
consolidation applies to an entity in which either (1) the at-risk equity is
insufficient to absorb expected losses without additional subordinated financial
support or (2) its at-risk equity holders as a group are not able to make
decisions that have a significant impact on the success or failure of the
entity's ongoing activities. A variable interest in a VIE, by definition, is an
asset, liability, equity, contractual arrangement or other economic interest
that absorbs the entity's variability.
In December 2003 FASB modified FIN 46 with FIN 46-R to make certain
technical corrections and to address certain implementation issues. FIN 46, as
originally issued, was effective immediately for VIEs created or acquired after
January 31, 2003. FIN 46-R delayed the effective date of the interpretation to
no later than March 31, 2004, (for calendar-year enterprises), except for
Special Purpose Entities ("SPEs") for which the effective date was December 31,
2003. The Company has adopted FIN 46-R for its investment in SPEs, equity method
joint ventures, its wholly owned subsidiaries that are subject to long-term
power purchase agreements and tolling arrangements, operating lease arrangements
containing fixed price purchase options and its wholly owned subsidiaries that
have issued mandatorily redeemable non-controlling preferred interests.
On application of FIN 46 the Company evaluated its investments in joint
ventures and operating lease arrangements containing fixed price purchase
options and concluded that, in some instances, these entities were VIEs.
However, in these instances, the Company was not the Primary Beneficiary, as the
Company would not absorb a majority of these entities' expected variability. An
enterprise that holds a significant variable interest in a VIE is required to
make certain disclosures regarding the nature and timing of its involvement with
the VIE and the nature, purpose, size and activities of the VIE. The fixed price
purchase options under the Company's operating lease arrangements were not
considered significant variable interests. However, the joint ventures in which
the Company has invested were considered significant variable interests. See
Note 5 for more information related to these joint venture investments.
An analysis was performed for 100% Company-owned subsidiaries with
significant long-term power sales or tolling agreements. Certain of the 100%
Company-owned subsidiaries were deemed to be VIEs and held power sales and
tolling contracts which may be considered variable interest under FIN 46-R.
However, in all cases, the Company absorbed a majority of the entity's
variability and continues to consolidate these 100% Company-owned subsidiaries.
The Company qualitatively determined that power sales or tolling agreements less
than 10 years in length and for less than 50% of the entity's capacity would not
cause the power purchaser to be the Primary Beneficiary, due to the length of
the economic life of the underlying assets. Also, power sales and tolling
agreements meeting the definition of a lease under EITF Issue No. 01-08,
"Determining Whether an Arrangement Contains a Lease," were not considered
variable interests, due to certain exclusions under FIN 46-R.
A similar analysis was performed for the Company's wholly owned
subsidiaries that have issued mandatorily redeemable non-controlling preferred
interests. These entities were determined to be VIEs in which the Company
absorbs the majority of the variability, primarily due to the debt
characteristics of the preferred interest, which are classified as debt in
accordance with SFAS No. 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity" in the Company's Consolidated
Condensed Balance Sheets. Consequently, the Company continues to consolidate
these wholly owned subsidiaries.
-12-
Significant judgment was required in making an assessment of whether or not
a VIE was a special purpose entity ("SPE") for purposes of adopting and applying
FIN 46-R, as of October 31, 2003. Entities that meet the definition of a
business outlined in FIN 46-R and that satisfy other formation and involvement
criteria are not subject to the FIN 46-R consolidation guidelines. The
definitional characteristics of a business include having: inputs such as
long-lived assets; the ability to obtain access to necessary materials and
employees; processes such as strategic management, operations and resource
management; and the ability to obtain access to the customers that purchase the
outputs of the entity. Since the current accounting literature does not provide
a definition of an SPE, the Company's assessment was primarily based on the
degree to which the VIE aligned with the definition of a business. Based on this
assessment, the Company determined that five VIE investments were in SPEs:
Calpine Northbrook Energy Marketing, LLC ("CNEM"), Power Contract Financing,
L.L.C. ("PCF") and the Calpine Capital Trusts I, II and III, and subject to FIN
46-R as of October 1, 2003.
On May 15, 2003, the Company's wholly owned subsidiary, CNEM, completed the
$82.8 million monetization of an existing power sales agreement with the
Bonneville Power Administration ("BPA"). CNEM borrowed $82.8 million secured by
the spread between the BPA contract and certain fixed power purchase contracts.
CNEM was established as a bankruptcy-remote entity and the $82.8 million loan is
recourse only to CNEM's assets and is not guaranteed by the Company. CNEM was
determined to be a VIE in which the Company was the Primary Beneficiary.
Accordingly, the entity's assets and liabilities were consolidated into the
Company's accounts as of June 30, 2003.
On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of Calpine
Energy Services, L.P. ("CES"), completed an offering of two tranches of Senior
Secured Notes Due 2006 and 2010 (collectively called the "PCF Notes"), totaling
$802.2 million. To facilitate the transaction, the Company formed PCF as a
wholly owned, bankruptcy remote entity with assets and liabilities consisting of
certain transferred power purchase and sales contracts, which serve as
collateral for the PCF Notes. The PCF Notes are non-recourse to the Company's
other consolidated subsidiaries. PCF was determined to be a VIE in which the
Company was the Primary Beneficiary. Accordingly, the entity's assets and
liabilities were consolidated into the Company's accounts as of June 30, 2003.
Upon the adoption of FIN 46-R at December 31, 2003, for the Company's
investments in SPEs, the Company determined that its equity investment in
Calpine Capital Trusts I, II and III ("the Trusts") was not considered at-risk
as defined in FIN 46-R and that the Company did not have a significant variable
interest in the Trusts. Consequently, the Company deconsolidated the Trusts.
In addition, as a result of the debt reserve monetization consummated on
June 2, 2004, discussed in Note 8, the Company was required to evaluate its
investment in the PCF and PCF III entities under FIN 46-R. The Company
determined that the entities were VIEs but the Company was not the Primary
Beneficiary and was, therefore, required to deconsolidate the entities.
The Company created CNEM, PCF, PCF III and Calpine Capital Trust I, II and
III to facilitate capital transactions. However, in cases such as this where the
Company has continuing involvement with the assets held by the deconsolidated
SPE, the Company accounts for the capital transaction with the SPE as a
financing rather than a sale under Emerging Issues Task Force Issue No. 88-18,
"Sales of Future Revenue" ("EITF 88-18") or Statement of Financial Accounting
Standard No. 140, "Accounting for Transfers and Servicing of Financial Assets
and Extinguishments of Liabilities" ("SFAS 140"), as appropriate. When EITF
88-18 and SFAS 140 require the Company to account for a transaction as a
financing, derecognition of the assets underlying the financing is prohibited,
and the proceeds received from the transaction must be recorded as debt.
Accordingly, in situations where the Company accounts for transactions as
financings under EITF 88-18 or SFAS 140, the Company continues to recognize the
assets and the debt of the deconsolidated SPE on its balance sheet. The table
below summarizes how the Company has accounted for its SPEs when it has
continuing involvement under ETF 88-18 or SFAS 140:
FIN 46-R Sale or
Treatment Financing
------------- ----------
CNEM......................................... Consolidate N/A
PCF.......................................... Deconsolidate Financing
PCF III...................................... Deconsolidate Financing
Calpine Capital Trust I, II and III.......... Deconsolidate Financing
On July 19, 2004, the Emerging Issues Task Force ("EITF") reached a
tentative conclusion on Issue No. 04-8 ("EITF 04-8"): "The Effect of
Contingently Convertible Debt on Diluted Earnings per Share" that would require
companies that have issued contingently convertible debt instruments, commonly
referred to as "Co-Cos," with a market price trigger to include the effects of
the conversion in earnings per share ("EPS"), regardless of whether the price
trigger had been met. Currently, Co-Cos are not included in EPS if the price
trigger has not been met. Typically, the affected instruments are convertible
into common shares of the issuer after the common stock price has exceeded a
-13-
predetermined threshold for a specified time period. If EITF 04-8 is finalized
as currently written, Calpine's $900 million of 4.75% Contingent Convertible
Senior Notes Due 2023 may be affected. The Company is still in the process of
evaluating what impact, if any, this new guidance will have on its diluted EPS.
3. Available-for-Sale Debt Securities
During the quarter, the Company exchanged 20.1 million shares of Calpine
common stock in privately negotiated transactions for $20.0 million par value of
HIGH TIDES I and $75.0 million par value of HIGH TIDES II. These repurchased
HIGH TIDES I and II are reflected on the balance sheet in Other Assets along
with previously repurchased HIGH TIDES I due to the deconsolidation of the
Calpine Capital Trusts upon the adoption of FIN 46-R. The Company is accounting
for the HIGH TIDES as available-for-sale in accordance with SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities" ("SFAS 115").
Therefore, the following HIGH TIDES were recorded at fair market value at June
30, 2004, with the differences from their repurchase price recorded in Other
Comprehensive Income (in thousands):
June 30, 2004
--------------------------------------------
Gross Gross
Unrealized Unrealized
Gains in Other Losses in Other
Repurchase Comprehensive Comprehensive Fair
Price Income/(Loss) Income/(Loss) Value
---------- -------------- --------------- --------
HIGH TIDES I....................................... $ 54,939 $ 980 $ -- $ 55,919
HIGH TIDES II ..................................... 71,341 -- (1,216) 70,125
--------- ------- ------- --------
Debt securities................................. $ 126,280 $ 980 $(1,216) $126,044
========= ======= ======= ========
See Note 16 for HIGH TIDES exchanged in privately negotiated transactions
subsequent to June 30, 2004.
4. Property, Plant and Equipment, Net and Capitalized Interest
As of June 30, 2004 and December 31, 2003, the components of property,
plant and equipment, net, are stated at cost less accumulated depreciation and
depletion as follows (in thousands):
June 30, December 31,
2004 2003
-------------- --------------
Buildings, machinery, and equipment............. $ 16,040,848 $ 13,226,310
Oil and gas properties, including pipelines..... 2,117,599 2,136,740
Geothermal properties........................... 467,932 460,602
Other........................................... 249,384 234,932
------------- --------------
18,875,763 16,058,584
Less: accumulated depreciation and depletion.... (2,100,264) (1,834,701)
-------------- --------------
16,775,499 14,223,883
Land............................................ 98,689 95,037
Construction in progress........................ 4,156,986 5,762,132
-------------- --------------
Property, plant and equipment, net.............. $ 21,031,174 $ 20,081,052
============== ==============
Capital Spending -- Construction and Development
Construction and Development costs in process consisted of the following at
June 30, 2004 (in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP CIP Costs Equipment
-------- ----------- ----------- ----------- ----------
Projects in active construction.......................... 9 $ 2,929,153 $ 980,425 $ -- $ --
Projects in advanced development......................... 13 720,982 585,866 129,158 --
Projects in suspended development........................ 6 463,320 203,437 12,993 --
Projects in early development............................ 3 -- -- 8,933 14,001
Other capital projects................................... NA 43,531 -- -- --
Unassigned............................................... NA -- -- -- 52,856
----------- ----------- --------- ---------
Total construction and development costs.............. $ 4,156,986 $ 1,769,728 $ 151,084 $ 66,857
=========== =========== ========= =========
-14-
Construction in Progress -- Construction in progress ("CIP") is primarily
attributable to gas-fired power projects under construction including
prepayments on gas and steam turbine generators and other long lead-time items
of equipment for certain development projects not yet in active construction.
Upon commencement of plant operation, these costs are transferred to the
applicable property category, generally buildings, machinery and equipment.
Projects in Active Construction -- The 9 projects in active construction
are estimated to come on line from September 2004 to June 2007. These projects
will bring on line approximately 4,266 MW of base load capacity (4,825 MW with
peaking capacity). Interest and other costs related to the construction
activities necessary to bring these projects to their intended use are being
capitalized. Five additional projects totaling 3,110 megawatts that were in
active construction in the beginning of the quarter went on line during the
quarter. At June 30, 2004, the estimated funding requirements to complete these
9 projects, net of expected project financing proceeds, is approximately $1.2
billion.
Projects in Advanced Development -- There are 13 projects in advanced
development. These projects will bring on line approximately 5,945 MW of base
load capacity (7,096 MW with peaking capacity). Interest and other costs related
to the development activities necessary to bring these projects to their
intended use are being capitalized. However, the capitalization of interest has
been suspended on two projects for which development activities are complete.
The estimated cost to complete the 13 projects in advanced development is
approximately $3.9 billion. The Company's current plan is to commence
construction with project financing, once power purchase agreements are
arranged.
Suspended Development Projects -- Due to current electric market
conditions, the Company has ceased capitalization of additional development
costs and interest expense on certain development projects on which work has
been suspended. Capitalization of costs may recommence as work on these projects
resumes, if certain milestones and criteria are met. These projects would bring
on line approximately 3,169 MW of base load capacity (3,629 MW with peaking
capacity). The estimated cost to complete the six projects is approximately $1.9
billion.
Projects in Early Development -- Costs for projects that are in early
stages of development are capitalized only when it is highly probable that such
costs are ultimately recoverable and significant project milestones are
achieved. Until then all costs, including interest costs, are expensed. The
projects in early development with capitalized costs relate to three projects
and include geothermal drilling costs and equipment purchases.
Other Capital Projects -- Other capital projects primarily consist of
enhancements to operating power plants, oil and gas and geothermal resource and
facilities development as well as software developed for internal use.
Unassigned Equipment -- As of June 30, 2004, the Company had made progress
payments on 4 turbines, 1 heat recovery steam generator and other equipment with
an aggregate carrying value of $66.9 million representing unassigned equipment
that is classified on the balance sheet as other assets because it is not
assigned to specific development and construction projects. The Company is
holding this equipment for potential use on future projects. It is possible that
some of this unassigned equipment may eventually be sold, potentially in
combination with the Company's engineering and construction services. For
equipment that is not assigned to development or construction projects, interest
is not capitalized.
Capitalized Interest -- The Company capitalizes interest on capital
invested in projects during the advanced stages of development and the
construction period in accordance with SFAS No. 34, "Capitalization of Interest
Cost" ("SFAS No. 34"), as amended by SFAS No. 58, "Capitalization of Interest
Cost in Financial Statements That Include Investments Accounted for by the
Equity Method (an Amendment of FASB Statement No. 34)" ("SFAS No. 58"). The
Company's qualifying assets include construction in progress, certain oil and
gas properties under development, construction costs related to unconsolidated
investments in power projects under construction, and advanced stage development
costs. For the three months ended June 30, 2004 and 2003, the total amount of
interest capitalized was $102.2 million and $116.5 million, respectively,
including $15.4 million and $18.8 million, respectively, of interest incurred on
funds borrowed for specific construction projects and $86.8 million and $97.7
million, respectively, of interest incurred on general corporate funds used for
construction. For the six months ended June 30, 2004 and 2003, the total amount
of interest capitalized was $210.7 million and $235.0 million, respectively,
including $34.0 million and $38.4 million, respectively, of interest incurred on
funds borrowed for specific construction projects and $176.7 million and $196.6
million, respectively, of interest incurred on general corporate funds used for
construction. Upon commencement of plant operation, capitalized interest, as a
component of the total cost of the plant, is amortized over the estimated useful
life of the plant. The decrease in the amount of interest capitalized during the
three and six months ended June 30, 2004 reflects the completion of construction
for several power plants and the result of the current suspension of certain of
the Company's development projects.
-15-
In accordance with SFAS No. 34, the Company determines which debt
instruments best represent a reasonable measure of the cost of financing
construction assets in terms of interest cost incurred that otherwise could have
been avoided. These debt instruments and associated interest cost are included
in the calculation of the weighted average interest rate used for capitalizing
interest on general funds. The primary debt instruments included in the rate
calculation of interest incurred on general corporate funds, are certain of the
Company's Senior Notes and term loan facilities and the secured working capital
revolving credit facility.
Impairment Evaluation -- All construction and development projects and
unassigned turbines are reviewed for impairment whenever there is an indication
of potential reduction in fair value. Equipment assigned to such projects is not
evaluated for impairment separately, as it is integral to the assumed future
operations of the project to which it is assigned. If it is determined that it
is no longer probable that the projects will be completed and all capitalized
costs recovered through future operations, the carrying values of the projects
would be written down to the recoverable value in accordance with the provisions
of SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets"
("SFAS No. 144"). The Company reviews its unassigned equipment for potential
impairment based on probability-weighted alternatives of utilizing the equipment
for future projects versus selling the equipment. Utilizing this methodology,
the Company does not believe that the equipment not committed to sale is
impaired.
5. Investments in Power Projects and Oil and Gas Properties
The Company's investments in power projects and oil and gas properties are
integral to its operations. As discussed in Note 2, the Company's joint venture
investments were evaluated under FIN 46-R to determine which, if any, entities
were VIEs. Based on this evaluation, the Company determined that the Acadia
Energy Center, Grays Ferry Power Plant, Whitby Cogeneration facility and the
Androscoggin Power Plant were VIEs, in which the Company held a significant
variable interest. However, based on a qualitative and quantitative assessment
of the expected variability in these entities, the Company was not the Primary
Beneficiary. Consequently, the Company continues to account for these VIEs and
its other joint venture investments in power projects in accordance with APB
Opinion No. 18, "The Equity Method of Accounting For Investments in Common
Stock" and FASB Interpretation No. 35, "Criteria for Applying the Equity Method
of Accounting for Investments in Common Stock (An Interpretation of APB Opinion
No. 18)."
Acadia Powers Partners, LLC ("Acadia") is the owner of a 1,160-megawatt
electric wholesale generation facility located in Louisiana and is a joint
venture between the Company and Cleco Corporation. The Company's involvement in
this VIE began upon formation of the entity in March 2000. The Company's maximum
potential exposure to loss at June 30, 2004, is limited to the book value of its
investment of approximately $220.3 million.
Grays Ferry Cogeneration Partnership ("Grays Ferry") is the owner of a
140-megawatt gas-fired cogeneration facility located in Pennsylvania and is a
joint venture between the Company and Trigen-Schuylkill Cogeneration, Inc. The
Company's involvement in this VIE began with its acquisition of the independent
power producer, Cogeneration Corporation of America, Inc. ("Cogen America") in
December 1999. The Grays Ferry joint venture project was part of the portfolio
of assets owned by Cogen America. The Company's maximum potential exposure to
loss at June 30, 2004, is limited to the book value of its investment of
approximately $49.0 million.
Androscoggin Energy LLC ("AELLC") is the owner of a 160-megawatt gas-fired
cogeneration facility located in Maine and is a joint venture between the
Company, Wisvest Corporation and Androscoggin Energy, Inc. The Company's
involvement in this VIE began with its acquisition of the independent power
producer, SkyGen Energy LLC ("SkyGen") in October 2000. The Androscoggin joint
venture project was part of the portfolio of assets owned by SkyGen. The
Company's maximum potential exposure to loss at June 30, 2004, is limited to
$32.1 million, which represents the book value of its investment of
approximately $14.5 million and a notes receivable balance due from AELLC of
$17.6 million as described below.
Whitby Energy LLP ("Whitby") is the owner of a 50-megawatt gas-fired
cogeneration facility located in Ontario, Canada and is a joint venture between
the Company and a privately held enterprise. The Company's involvement in this
VIE began with its acquisition of a portfolio of assets from Westcoast Energy
Inc. ("Westcoast") in September 2001, which included the Whitby joint venture
project. The Company's maximum potential exposure to loss at June 30, 2004, is
limited to the book value of its investment of approximately $34.8 million.
-16-
The following investments are accounted for under the equity method (in
thousands):
Ownership Investment Balance at
Interest as --------------------------
of
June 30, June 30, December 31,
2004 2004 2003
----------- ----------- -----------
Acadia Energy Center.................................................. 50.0% $ 220,323 $ 221,038
Valladolid III IPP.................................................... 45.0% 72,626 67,320
Grays Ferry Power Plant (1)........................................... 50.0% 49,008 53,272
Whitby Cogeneration (2)............................................... 15.0% 34,774 31,033
Calpine Natural Gas Trust............................................. 25.0% 24,712 28,598
Androscoggin Power Plant.............................................. 32.3% 14,510 11,823
Aries Power Plant (3)................................................. 100.0% -- 58,205
Other................................................................. -- 1,350 1,460
----------- -----------
Total investments in power projects and oil and gas properties..... $ 417,303 $ 472,749
=========== ===========
- ------------
<FN>
(1) On March 23, 2004, the Company completed the acquisition of the remaining
20% interest in Calpine Cogen. As a result of the acquisition, the
Company's ownership percentage in the Grays Ferry Power Plant increased to
50%.
(2) Whitby is owned 50% by the Company but a 70% economic interest in the
Company's ownership percentage has effectively been transferred to the
Calpine Power Income Fund through a loan from Calpine Power Limited
Partnership to the Company's entity which holds the investment interest in
Whitby.
(3) On March 26, 2004, the Company acquired the remaining 50 percent interest
in Aries Power Plant. Accordingly, this plant is consolidated as of June
30, 2004.
</FN>
The third-party debt on the books of the unconsolidated investments is not
reflected on the Company's Consolidated Condensed Balance Sheets. At June 30,
2004, third-party investee debt is approximately $178.7 million. Based on the
Company's pro rata ownership share of each of the investments, the Company's
share would be approximately $58.3 million. However, all such debt is
non-recourse to the Company.
The Company owns a 32.3% interest in the unconsolidated equity method
investee AELLC. AELLC owns the 160-MW Androscoggin Energy Center located in
Maine and has construction debt of $59.3 million outstanding as of June 30,
2004. The debt is non-recourse to the Company (the "AELLC Non-Recourse
Financing"). On June 30, 2004, and December 31, 2003, the Company's investment
balance was $14.5 million and $11.8 million, respectively, and its notes
receivable balance due from AELLC was $17.6 million and $13.3 million,
respectively. On and after August 8, 2003, AELLC received letters from its
lenders claiming that certain events of default had occurred under the credit
agreement for the AELLC Non-Recourse Financing, including, among other things,
that the project had been and remained in default under its credit agreement
because the lending syndication had declined to extend the dates for the
conversion of the construction loan to a term loan by a certain date. AELLC
disputes the purported defaults. Also, the steam host for the AELLC project,
International Paper Company ("IP"), filed a complaint against AELLC in October
2000, which is discussed in more detail in Note 13. IP's complaint has been a
complicating factor in converting the construction debt to long term financing.
As a result of these events, the Company reviewed its investment and notes
receivable balances and believes that the assets are not impaired. The Company
further believes that AELLC will eventually be able to convert the construction
loan to a term loan.
-17-
The following details the Company's income and distributions from
investments in unconsolidated power projects and oil and gas properties (in
thousands):
Income (Loss) from
Unconsolidated
Investments in Power
Projects
and Oil and Gas Properties Distributions
-------------------------- ------------------------
For the Six Months Ended June 30,
-----------------------------------------------------
2004 2003 2004 2003
----------- ----------- ----------- -----------
Acadia Energy Center....................................... $ 6,913 $ 66,058 $ 8,454 $119,950
Aries Power Plant.......................................... (4,089) (599) -- --
Grays Ferry Power Plant.................................... (2,060) (1,929) -- --
Whitby Cogeneration........................................ 709 1,231 1,515 --
Calpine Natural Gas Trust.................................. 2,593 -- 4,586 --
Androscoggin Power Plant................................... (2,945) (3,804) -- --
Gordonsville Power Plant (1)............................... -- 3,210 -- 1,050
Other...................................................... 174 194 142 15
--------- --------- -------- --------
Total................................................... $ 1,295 $ 64,361 $ 14,697 $121,015
========= ========= ======== ========
Interest income on notes receivable from
power projects (2)........................................ $ 493 $ 114
--------- ---------
Total................................................... $ 1,788 $ 64,475
========= =========
- ------------
<FN>
The Company provides for deferred taxes on its share of earnings.
(1) On November 26, 2003, the Company completed the sale of its 50 percent
interest in the Gordonsville Power Plant.
(2) At June 30, 2004, and December 31, 2003, notes receivable from power
projects represented an outstanding loan to the Company's investment,
Androscoggin Energy Center LLC, in the amounts of $17.6 million and $13.3
million, respectively.
</FN>
Related-Party Transactions with Equity Method Affiliates
The Company and certain of its equity method affiliates have entered into
various service agreements with respect to power projects and oil and gas
properties. Following is a general description of each of the various
agreements:
Operation and Maintenance Agreements -- The Company operates and maintains
the Acadia Power Plant and Androscoggin Power Plant. This includes routine
maintenance, but not major maintenance, which is typically performed under
agreements with the equipment manufacturers. Responsibilities include
development of annual budgets and operating plans. Payments include
reimbursement of costs, including Calpine's internal personnel and other costs,
and annual fixed fees.
Administrative Services Agreements -- The Company handles administrative
matters such as bookkeeping for certain unconsolidated investments. Payment is
on a cost reimbursement basis, including Calpine's internal costs, with no
additional fee.
Power Marketing Agreements -- Under agreements with the Company's
Androscoggin Power Plant, CES can either market the plant's power as the power
facility's agent or buy the power directly. Terms of any direct purchase are to
be agreed upon at the time and incorporated into a transaction confirmation.
Historically, CES has generally bought the power from the power facility rather
than acting as its agent.
Gas Supply Agreement -- CES can be directed to supply gas to the
Androscoggin Power Plant facility pursuant to transaction confirmations between
the facility and CES. Contract terms are reflected in individual transaction
confirmations.
-18-
The power marketing and gas supply contracts with CES are accounted for as
either purchase and sale arrangements or as tolling arrangements. In a purchase
and sale arrangement, title and risk of loss associated with the purchase of gas
is transferred from CES to the project at the gas delivery point. In a tolling
arrangement, title to fuel provided to the project does not transfer, and CES
pays the project a capacity and a variable fee based on the specific terms of
the power marketing and gas supply agreements. In addition to the contracts
specified above, CES maintains two tolling agreements with the Acadia facility.
All of the other power marketing and gas supply contracts are accounted for
as purchases and sales.
The related party balances with equity method affiliates as of June 30,
2004 and December 31, 2003, reflected in the accompanying Consolidated Condensed
Balance Sheets, and the related party transactions with equity method affiliates
for the three and six months ended June 30, 2004, and 2003, reflected in the
accompanying Consolidated Condensed Statements of Operations are summarized as
follows (in thousands):
June 30, December 31,
2004 2003
------------ ------------
Accounts receivable.............................. $ 4,069 $ 1,156
Accounts payable................................. 10,820 12,172
Interest receivable.............................. 1,914 2,074
Note Receivable.................................. 17,602 13,262
Other receivables................................ 10,436 8,794
2004 2003
------------ ------------
For the Three Months Ended June 30,
Revenue.......................................... $ 52 $ --
Cost of Revenue.................................. 31,373 16,591
Maintenance fee revenue.......................... 39 160
Interest income.................................. 259 85
For the Six Months Ended June 30,
Revenue.......................................... $ 699 $ 455
Cost of Revenue.................................. 64,119 31,083
Maintenance fee revenue.......................... 214 303
Interest income.................................. 493 114
Gain on sale of assets........................... 6,240 --
6. King City Restructuring
The California Power Income Fund ("CPIF") acquired the King City facility
from a third party in a transaction that closed May 19, 2004. CPIF became the
new lessor of the facility, which it purchased subject to the Company's
pre-existing operating lease. The Company restructured certain provisions of the
operating lease, including a 10-year extension and the elimination of the
collateral requirements necessary to support the original lease payments.
In the first quarter of 2004, the Company reclassified the securities that
served as collateral under the original lease for the King City power plant from
held-to-maturity to available-for-sale in accordance with SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities" ("SFAS No.
115"). At the close of the restructuring transaction, the Company sold the
securities for total proceeds of $95.4 million and recorded a pre-tax gain of
$12.3 million in Other Income. Also, in contemplation of the sale, the Company
entered into an interest rate swap with a financial institution with the intent
to hedge against a decline in value of the collateral debt securities. The swap
did not meet the required criteria for hedge effectiveness under SFAS No. 133
and, as a result, the Company recorded all changes in the swap's fair value
between the dates of inception and settlement in Other Income. Upon settlement
of the swap, the Company had recognized a cumulative gain of $5.2 million.
The Company used the proceeds from the sale of the securities to redeem a
preferred interest in the project totaling $82.0 million. The preferred interest
had been recorded as debt under SFAS No. 150. The Company expensed approximately
$1.2 million in deferred finance costs related to the original issuance of the
preferred interest and paid a $3.0 million termination fee. These debt
extinguishment costs were recorded in Other Expense.
Due to the lease extension and other modifications to the original lease,
the lease classification was reevaluated under SFAS No. 13 "Accounting for
Leases" and determined to be a capital lease. In determining the new lease
classification, the Company included all increases due to step rent
provision/escalation clauses in the minimum lease payments. Lease concessions
and other executory costs such as taxes and insurance are excluded from the
minimum lease payments. Certain future capital improvements associated with the
leased facility may be deemed leasehold improvements and will be amortized over
the shorter of the term of the lease or the economic life of the capital
improvement.
-19-
At June 30, 2004, the asset balance for the leased asset was $114.9
million. The leased asset will be amortized over the 24-year lease term. The
lease agreement provides for the Company to pay taxes, maintenance, insurance,
and certain other operating costs of the leased property. The following is a
schedule by years of future minimum lease payments under the capital lease
together with the present value of the net minimum lease payments as of June 30,
2004 (in thousands):
Year Ending December 31:
2004....................................................... $ 13,277
2005....................................................... 16,699
2006....................................................... 16,458
2007....................................................... 16,552
2008....................................................... 16,199
Thereafter................................................. 187,798
-----------
Total minimum lease payments............................ 266,983
Less: Amount representing interest(1)......................... 172,041
-----------
Present value of net minimum lease payments................ $ 94,942
Less: Capital lease obligation, current portion............... 4,051
-----------
Capital lease obligation, net of current portion........... $ 90,891
===========
- ------------
(1) Amount necessary to reduce net minimum lease payments to preset value
calculated at the incremental rate at the time of acquisition.
CPIF is considered a related party to the Company as the Company holds
three of the seven CPIF Trustee positions. Contemporaneous with the acquisition,
Calpine Canada Power Ltd., a wholly owned subsidiary of the Company, issued a
6-year promissory note to a CPIF affiliate, of which $34.4 million was
outstanding at June 30, 2004.
7. Senior Notes
On April 26, 2004, we announced the completion of consent solicitations to
effect certain amendments to five indentures governing the Company's outstanding
10-1/2% Senior Notes Due 2006, 8-3/4% Senior Notes Due 2007, 7-7/8% Senior Notes
Due 2008, 7-5/8% Senior Notes Due 2006 and 7-3/4% Senior Notes Due 2009.
Supplemental indentures effecting such amendments were executed by the Company
and the respective trustee for each series of senior notes as of April 26, 2004.
During the three months ended June 30, 2004, the Company repurchased $46.6
million in principal amount of its outstanding Senior Notes in exchange for
$41.5 million in cash. The Company recorded a pre-tax gain on these transactions
in the amount of $4.9 million, net of write-offs of unamortized deferred
financing costs and the unamortized premiums or discounts.
8. Financing
On May 26, 2004, the Company and Jersey Central Power & Light Company
("JCPL") terminated their existing toll arrangements with the Newark and Parlin
power plants, resulting in a pre-tax gain of $100.6 million. Proceeds from this
transaction were used to retire project financing debt of $78.8 million. In
conjunction with this termination, Utility Contract Funding II ("UCF"), a wholly
owned subsidiary of CES, entered into a long-term power purchase agreement with
JCPL. UCF was then sold. The Company recognized an $85.4 million pre-tax gain on
the sale of UCF. The total pre-tax gain, net of transaction costs and the
write-off of unamortized deferred financing costs, was $171.5 million.
On June 2, 2004, the Company's wholly owned subsidiary, Power Contract
Financing III, LLC ("PCF III"), issued $85.0 million of zero coupon notes
collateralized PCF III's ownership of PCF. PCF III owns all of the equity
interests in Power Contract Financing, L.L.C., which holds the California
Department of Water Resources I contract monetized in June 2003 and maintains a
debt reserve fund, which had a balance of approximately $94.4 million at June
30, 2004. The Company received cash proceeds of approximately $48.0 million from
the issuance of the notes.
On June 11, 2004, Citrus Trading Corp. negotiated the early partial
termination of its out-of-the-money gas contract with the Auburndale facility.
The Company recognized a pre-tax gain of $16.4 million as a result of this
transaction. The pre-tax gain was partially offset by the recognition of $4.7
million in interest expense on the distribution of a share of the proceeds to an
ArcLight affiliate, which holds a 70% preferred equity interest in the
Auburndale power plant. The net pre-tax gain on this transaction was $11.7
million.
On June 29, 2004, Rocky Mountain Energy Center, LLC and Riverside Energy
Center, LLC, wholly owned stand-alone subsidiaries of the Company's Calpine
Riverside Holdings, LLC subsidiary, received funding in the aggregate amount of
$661.5 million comprised of $633.4 million of First Priority Secured Floating
-20-
Rate Term Loans Due 2011 priced at LIBOR plus 425 basis points and $28.1
million letter of credit-linked deposit facility. Net proceeds from the loans,
after transaction costs and fees, were used to pay final construction costs and
refinance amounts outstanding under the $250 million non-recourse project
financing for the Rocky Mountain facility and the $230 million non-recourse
project financing for the Riverside facility. In connection with this
refinancing, the Company wrote off $13.2 million in deferred financing costs. In
addition, approximately $160.0 million was used to reimburse the Company for
costs incurred in connection with the development and construction of the Rocky
Mountain and Riverside facilities. The Company also received approximately $79.0
million in proceeds via a combination of cash and increased credit capacity as a
result of the elimination of certain reserves and cancellation of letters of
credit associated with the original non-recourse project financings.
During the three months ended June 30, 2004, the Company exchanged 20.1
million Calpine common shares in privately negotiated transactions for $20.0
million par value of HIGH TIDES I and $75.0 million par value of HIGH TIDES II.
The repurchased HIGH TIDES are reflected in our balance sheet in other assets as
available for sale securities. See Note 3 for more information regarding the
Company's available for sale securities.
Annual Debt Maturities
The annual principal repayments or maturities of notes payable and
borrowings under lines of credit, notes payable to Calpine Capital Trusts,
preferred interests, construction/project financing, 2006 Convertible Senior
Notes, 2023 Convertible Notes, senior notes and term loans, CCFC I financing,
CalGen/CCFC II financing and capital lease obligations, net of unamortized
premiums and discounts, as of June 30, 2004, are as follows (in thousands):
July through December 2004.......................... $ 169,732
2005................................................ 580,784
2006................................................ 751,721
2007................................................ 2,086,843
2008................................................ 2,615,479
Thereafter.......................................... 11,866,581
--------------
Total............................................ $ 18,071,140
==============
9. Discontinued Operations
Set forth below are all of the Company's asset disposals by reportable
segment that impacted the Company's Consolidated Condensed Financial Statements
as of June 30, 2004 and December 31, 2003:
Corporate and Other
On July 31, 2003, the Company completed the sale of its specialty data
center engineering business and recorded a pre-tax loss on the sale of $11.6
million.
Oil and Gas Production and Marketing
On November 20, 2003, the Company completed the sale of its Alvin South
Field oil and gas assets located near Alvin, Texas for approximately $0.06
million to Cornerstone Energy, Inc. As a result of the sale, the Company
recognized a pre-tax loss of $0.2 million.
Electric Generation and Marketing
On January 15, 2004, the Company completed the sale of its 50-percent
undivided interest in the 545 megawatt Lost Pines 1 Power Project to GenTex
Power Corporation, an affiliate of the Lower Colorado River Authority (LCRA).
Under the terms of the agreement, Calpine received a cash payment of $146.8
million and recorded a pre-tax gain of $35.3 million. In addition, CES entered
into a tolling agreement with LCRA providing for the option to purchase 250
megawatts of electricity through December 31, 2004. At December 31, 2003, the
Company's undivided interest in the Lost Pines facility was classified as "held
for sale."
Summary
The Company made reclassifications to current and prior period financial
statements to reflect the sale or designation as "held for sale" of these oil
and gas and power plant assets and liabilities and to separately classify the
operating results of the assets sold and gain on sale of those assets from the
operating results of continuing operations to discontinued operations.
-21-
The tables below present significant components of the Company's income
from discontinued operations for the three and six months ended June 30, 2004,
and 2003, respectively (in thousands):
Three Months Ended June 30, 2004
------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- --------- ----------
Total revenue................................................ $ -- $ -- $ -- $ --
========== ==== ==== ==========
Gain on disposal before taxes................................ $ -- $ -- $ -- $ --
Operating income from discontinued operations before taxes... 324 -- -- 324
---------- ---- ---- ----------
Income from discontinued operations before taxes............. $ 324 $ -- $ -- 324
========== ==== ==== ==========
Gain on disposal, net of tax................................. $ -- $ -- $ -- $ --
Operating income from discontinued operations, net of tax.... 198 -- -- 198
---------- ---- ---- ----------
Income from discontinued operations, net of tax.............. $ 198 $ -- $ -- $ 198
========== ==== ==== ==========
Three Months Ended June 30, 2003
------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- --------- ----------
Total revenue................................................ $ 20,558 $ 190 $ 1,985 $ 22,733
========== ===== ======== ==========
Loss on disposal before taxes................................ $ -- $ -- $ (3,294) $ (3,294)
Operating income (loss) from discontinued operations
before taxes................................................ 2,287 116 (10,584) (8,181)
---------- ----- -------- ----------
Income (loss) from discontinued operations before taxes...... $ 2,287 $ 116 $(13,878) $ (11,475)
========== ===== ======== ==========
Loss on disposal, net of tax................................. $ -- $ -- $ (2,042) $ (2,042)
Operating income (loss) from discontinued operations,
net of tax.................................................. 1,486 71 (6,506) (4,949)
---------- ----- -------- ----------
Income (loss) from discontinued operations, net of tax....... $ 1,486 $ 71 $ (8,548) $ (6,991)
========== ===== ======== ==========
Six Months Ended June 30, 2004
------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- --------- ----------
Total revenue................................................ $ 2,679 $ -- $ -- $ 2,679
========== ===== ===== ==========
Gain on disposal before taxes................................ $ 35,327 $ -- $ -- $ 35,327
Operating income from discontinued operations before taxes... 180 -- -- 180
---------- ----- ----- ----------
Income from discontinued operations before taxes............. $ 35,507 $ -- $ -- 35,507
========== ===== ===== ==========
Gain on disposal, net of tax................................. $ 22,951 $ -- $ -- $ 22,951
Operating income from discontinued operations, net of tax.... 104 -- -- 104
---------- ----- ----- ----------
Income from discontinued operations, net of tax.............. $ 23,055 $ -- $ -- $ 23,055
========== ===== ===== ==========
-22-
Six Months Ended June 30, 2003
------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- --------- ----------
Total revenue................................................ $ 39,061 $ 268 $ 3,748 $ 43,077
========== ===== ======== ==========
Loss on disposal before taxes................................ $ -- $ -- $ (3,294) $ (3,294)
Operating income (loss) from discontinued operations
before taxes................................................ 3,165 146 (13,289) (9,978)
---------- ----- -------- ----------
Income (loss) from discontinued operations before taxes...... $ 3,165 $ 146 $(16,583) $ (13,272)
========== ===== ======== ==========
Loss on disposal, net of tax................................. $ -- $ -- $ (2,042) $ (2,042)
Operating income (loss) from discontinued operations,
net of tax.................................................. 2,056 91 (8,102) (5,955)
---------- ----- -------- ----------
Income (loss) from discontinued operations, net of tax....... $ 2,056 $ 91 $(10,144) $ (7,997)
========== ===== ======== ==========
10. Derivative Instruments
Commodity Derivative Instruments
As an independent power producer primarily focused on generation of
electricity using gas-fired turbines, the Company's natural physical commodity
position is "short" fuel (i.e., natural gas consumer) and "long" power (i.e.,
electricity seller). To manage forward exposure to price fluctuation in these
commodities, the Company enters into derivative commodity instruments. The
Company enters into commodity instruments to convert floating or indexed
electricity and gas prices to fixed prices in order to lessen its vulnerability
to reductions in electric prices for the electricity it generates, and to
increases in gas prices for the fuel it consumes in its power plants. The
Company seeks to "self-hedge" its gas consumption exposure to an extent with its
own gas production position. The hedging, balancing, and optimization activities
that the Company engages in are directly related to the Company's asset-based
business model of owning and operating gas-fired electric power plants and are
designed to protect the Company's "spark spread" (the difference between the
Company's fuel cost and the revenue it receives for its electric generation).
The Company hedges exposures that arise from the ownership and operation of
power plants and related sales of electricity and purchases of natural gas. The
Company also utilizes derivatives to optimize the returns it is able to achieve
from these assets. From time to time the Company has entered into contracts
considered energy trading contracts under EITF Issue No. 02-3. However, the
Company's traders have low capital at risk and value at risk limits for energy
trading, and its risk management policy limits, at any given time, its net sales
of power to its generation capacity and limits its net purchases of gas to its
fuel consumption requirements on a total portfolio basis. This model is markedly
different from that of companies that engage in significant commodity trading
operations that are unrelated to underlying physical assets. Derivative
commodity instruments are accounted for under the requirements of SFAS No. 133.
The Company also routinely enters into physical commodity contracts for
sales of its generated electricity and sales of its natural gas production to
ensure favorable utilization of generation and production assets. Such contracts
often meet the criteria of SFAS No. 133 as derivatives but are generally
eligible for the normal purchases and sales exception. Some of those contracts
that are not deemed normal purchases and sales can be designated as hedges of
the underlying consumption of gas or production of electricity.
Interest Rate and Currency Derivative Instruments
The Company also enters into various interest rate swap agreements to hedge
against changes in floating interest rates on certain of its project financing
facilities and to adjust the mix between fixed and floating rate debt in our
capital structure to desired levels. The interest rate swap agreements
effectively convert floating rates into fixed rates so that the Company can
predict with greater assurance what its future interest costs will be and
protect itself against increases in floating rates.
In conjunction with its capital markets activities, the Company enters into
various forward interest rate agreements to hedge against interest rate
fluctuations that may occur after the Company has decided to issue long-term
fixed rate debt but before the debt is actually issued. The forward interest
rate agreements effectively prevent the interest rates on anticipated future
long-term debt from increasing beyond a certain level, allowing the Company to
predict with greater assurance what its future interest costs on fixed rate
long-term debt will be.
-23-
Also in conjunction with its capital market activities, the Company enters
into various interest rate swap agreements to hedge against the changes in fair
value on certain of its fixed rate Senior Notes. These interest rate swap
agreements effectively convert fixed rates into floating rates so that the
Company can predict with greater assurance what the fair value of its fixed rate
Senior Notes will be and protect itself against unfavorable future fair value
movements.
The Company enters into various foreign currency swap agreements to hedge
against changes in exchange rates on certain of its senior notes denominated in
currencies other than the U.S. dollar. The foreign currency swaps effectively
convert floating exchange rates into fixed exchange rates so that the Company
can predict with greater assurance what its U.S. dollar cost will be for
purchasing foreign currencies to satisfy the interest and principal payments on
these senior notes.
Summary of Derivative Values
The table below reflects the amounts (in thousands) that are recorded as
assets and liabilities at June 30, 2004, for the Company's derivative
instruments:
Commodity
Interest Rate Derivative Total
Derivative Instruments Derivative
Instruments Net Instruments
------------- ------------- -------------
Current derivative assets................................................ $ 1,271 $ 337,534 $ 338,805
Long-term derivative assets.............................................. 3,923 557,405 561,328
---------- ------------ -------------
Total assets.......................................................... $ 5,194 $ 894,939 $ 900,133
========== ============ =============
Current derivative liabilities........................................... $ 28,260 $ 354,837 $ 383,097
Long-term derivative liabilities......................................... 68,851 530,644 599,495
---------- ------------ -------------
Total liabilities..................................................... $ 97,111 $ 885,481 $ 982,592
========== ============ =============
Net derivative assets (liabilities)................................ $ (91,917) $ 9,458 $ (82,459)
========== ============ =============
Of the Company's net derivative assets, $366.6 million and $67.2 million
are net derivative assets of Power Contract Financing, L.L.C. and Calpine
Northbrook Energy Marketing, LLC ("CNEM"), respectively, each of which is an
entity with its existence separate from the Company and other subsidiaries of
the Company. The Company fully consolidates CNEM and, as discussed more fully in
Note 2, the Company records the derivative assets of PCF in its balance sheet.
At any point in time, it is highly unlikely that total net derivative
assets and liabilities will equal accumulated OCI, net of tax from derivatives,
for three primary reasons:
Tax effect of OCI -- When the values and subsequent changes in values of
derivatives that qualify as effective hedges are recorded into OCI, they are
initially offset by a derivative asset or liability. Once in OCI, however, these
values are tax effected against a deferred tax liability or asset account,
thereby creating an imbalance between net OCI and net derivative assets and
liabilities.
Derivatives not designated as cash flow hedges and hedge ineffectiveness --
Only derivatives that qualify as effective cash flow hedges will have an
offsetting amount recorded in OCI. Derivatives not designated as cash flow
hedges and the ineffective portion of derivatives designated as cash flow hedges
will be recorded into earnings instead of OCI, creating a difference between net
derivative assets and liabilities and pre-tax OCI from derivatives.
Termination of effective cash flow hedges prior to maturity -- Following
the termination of a cash flow hedge, changes in the derivative asset or
liability are no longer recorded to OCI. At this point, an accumulated OCI
balance remains that is not recognized in earnings until the forecasted
initially hedged transactions occur. As a result, there will be a temporary
difference between OCI and derivative assets and liabilities on the books until
the remaining OCI balance is recognized in earnings.
-24-
Below is a reconciliation of the Company's net derivative assets to its
accumulated other comprehensive loss, net of tax from derivative instruments at
June 30, 2004 (in thousands):
Net derivative liabilities........................................................................ $ (82,459)
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness............... (73,512)
Cash flow hedges terminated prior to maturity..................................................... (90,027)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges....... 77,334
Accumulated OCI from unconsolidated investees..................................................... 23,170
------------
Accumulated other comprehensive loss from derivative instruments, net of tax(1)................... $ (145,494)
============
- ------------
<FN>
(1) Amount represents one portion of the Company's total accumulated OCI
balance. See Note 11 for further information.
</FN>
The asset and liability balances for the Company's commodity derivative
instruments represent the net totals after offsetting certain assets against
certain liabilities under the criteria of FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB
Opinion No. 10 and FASB Statement No. 105)" ("FIN 39"). For a given contract,
FIN 39 will allow the offsetting of assets against liabilities so long as four
criteria are met: (1) each of the two parties under contract owes the other
determinable amounts; (2) the party reporting under the offset method has the
right to set off the amount it owes against the amount owed to it by the other
party; (3) the party reporting under the offset method intends to exercise its
right to set off; and; (4) the right of set-off is enforceable by law. The table
below reflects both the amounts (in thousands) recorded as assets and
liabilities by the Company and the amounts that would have been recorded had the
Company's commodity derivative instrument contracts not qualified for offsetting
as of June 30, 2004.
June 30, 2004
------------------------------
Gross Net
-------------- --------------
Current derivative assets.................. $ 713,307 $ 337,534
Long-term derivative assets................ 1,043,294 557,405
-------------- --------------
Total derivative assets................. $ 1,756,601 $ 894,939
============== ==============
Current derivative liabilities............. $ 730,610 $ 354,837
Long-term derivative liabilities........... 1,016,533 530,644
-------------- --------------
Total derivative liabilities............ $ 1,747,143 $ 885,481
============== ==============
Net commodity derivative assets...... $ 9,458 $ 9,458
============== ==============
The table above excludes the value of interest rate and currency derivative
instruments.
The tables below reflect the impact of the Company's derivative instruments
on its pre-tax earnings, both from cash flow hedge ineffectiveness and from the
changes in market value of derivatives not designated as hedges of cash flows,
for the three and six months ended June 30, 2004 and 2003, respectively (in
thousands):
Three Months Ended June 30,
----------------------------------------------------------------------------------------
2004 2003
----------------------------------------- -------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ ---------- --------------- ------------ ----------
Natural gas derivatives(1)..... $ 317 $ (3,737) $ (3,420) $ 2,067 $ 3,556 $ 5,623
Power derivatives(1)........... 666 (26,159) (25,493) (1,612) (11,232) (12,844)
Interest rate derivatives(2)... (550) 5,939 5,389 (275) -- (275)
------- --------- ---------- -------- --------- ---------
Total....................... $ 433 $ (23,957) $ (23,524) $ 180 $ (7,676) $ (7,496)
======= ========= ========== ======== ========= =========
-25-
Six Months Ended June 30,
----------------------------------------------------------------------------------------
2004 2003
----------------------------------------- -------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ ---------- --------------- ------------ ----------
Natural gas derivatives(1)..... $ 5,763 $ (3,102) $ 2,661 $ 8,180 $ 1,579 $ 9,759
Power derivatives(1)........... 126 (36,645) (36,519) (4,638) (13,113) (17,751)
Interest rate derivatives(2)... (948) 6,035 5,087 (484) -- (484)
------- ---------- ---------- -------- --------- ---------
Total....................... $ 4,941 $ (33,712) $ (28,771) $ 3,058 $ (11,534) $ (8,476)
======= ========== ========== ======== ========= =========
- ------------
<FN>
(1) Represents the unrealized portion of mark-to-market activity on gas and
power transactions. The unrealized portion of mark-to-market activity is
combined with the realized portions of mark-to-market activity and
presented in the Consolidated Statements of Operations as mark-to-market
activities, net.
(2) Recorded within Other Income
</FN>
The table below reflects the contribution of the Company's cash flow hedge
activity to pre-tax earnings based on the reclassification adjustment from OCI
to earnings for the three and six months ended June 30, 2004 and 2003,
respectively (in thousands):
Three Months Ended June 30,
---------------------------
2004 2003
------------ ------------
Natural gas and crude oil derivatives............... $ 25,040 $ (2,998)
Power derivatives................................... (30,255) (4,223)
Interest rate derivatives........................... (7,194) (3,451)
Foreign currency derivatives........................ (496) (729)
----------- -----------
Total derivatives................................ $ (12,905) $ (11,401)
=========== ===========
Six Months Ended June 30,
---------------------------
2004 2003
------------ ------------
Natural gas and crude oil derivatives............... $ 25,233 $ 32,164
Power derivatives................................... (43,023) (55,549)
Interest rate derivatives........................... (9,966) (14,093)
Foreign currency derivatives........................ (1,012) 11,828
----------- ------------
Total derivatives................................ $ (28,768) $ (25,650)
=========== ===========
As of June 30, 2004 the maximum length of time over which the Company was
hedging its exposure to the variability in future cash flows for forecasted
transactions was 7.5 and 12.5 years, for commodity and interest rate derivative
instruments, respectively. The Company estimates that pre-tax losses of $149.6
million would be reclassified from accumulated OCI into earnings during the
twelve months ended June 30, 2005, as the hedged transactions affect earnings
assuming constant gas and power prices, interest rates, and exchange rates over
time; however, the actual amounts that will be reclassified will likely vary
based on the probability that gas and power prices as well as interest rates and
exchange rates will, in fact, change. Therefore, management is unable to predict
what the actual reclassification from OCI to earnings (positive or negative)
will be for the next twelve months.
The table below presents (in thousands) the pre-tax gains (losses)
currently held in OCI that will be recognized annually into earnings, assuming
constant gas and power prices, interest rates, and exchange rates over time.
2009 &
2004 2005 2006 2007 2008 After Total
----------- ----------- ----------- ----------- ----------- ----------- ------------
Gas OCI.................... $ 30,075 $ 22,896 $ 43,672 $ 943 $ 853 $ 2,118 $ 100,557
Power OCI.................. (112,210) (93,270) (49,157) (2,273) 201 435 (256,274)
Interest rate OCI.......... (9,594) (16,731) (8,258) (4,444) (1,866) (20,143) (61,036)
-
Foreign currency OCI....... (869) (1,872) (1,872) (1,481) 17 -- (6,077)
---------- ---------- ---------- ---------- ---------- ---------- -----------
Total pre-tax OCI....... $ (92,598) $ (88,977) $ (15,615) $ (7,255) $ (795) $ (17,590) $ (222,830)
========== ========== ========== ========== ========== ========== ===========
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11. Comprehensive Income (Loss)
Comprehensive income is the total of net income and all other non-owner
changes in equity. Comprehensive income includes the Company's net income,
unrealized gains and losses from derivative instruments that qualify as cash
flow hedges and the effects of foreign currency translation adjustments. The
Company reports Accumulated Other Comprehensive Income ("AOCI") in its
Consolidated Balance Sheet. The tables below detail the changes during the six
months ended June 30, 2004 and 2003, in the Company's AOCI balance and the
components of the Company's comprehensive income (in thousands):
Comprehensive
Income (Loss)
Total for the Three
Accumulated Months Ended
Available- Foreign Other March 31, 2004
Cash Flow for-Sale Currency Comprehensive and June 30,
Hedges Investments Translation Income 2004
----------- ----------- ----------- -------------- --------------
Accumulated other comprehensive income (loss) at
January 1, 2004.................................... $ (130,419) $ -- $ 187,013 $ 56,594
Net loss for the three months ended March 31, 2004.. $ (71,192)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the
three months ended March 31, 2004............ 4,426
Reclassification adjustment for loss included
in net loss for the three months ended
March 31, 2004............................... 15,863
Income tax provision for the three months
ended March 31, 2004......................... (7,224)
---------- --------
13,065 13,065 13,065
Available-for-sale investments:
Pre-tax gain on available-for-sale investments
for the three months ended March 31, 2004.... 19,526
Income tax provision for the three months
ended March 31, 2004......................... (7,709)
--------
11,817 11,817 11,817
Foreign currency translation gain for the
three months ended March 31, 2004............ 2,078 2,078 2,078
---------- --------- -------- ---------
Total comprehensive loss for the three months ended
March 31, 2004..................................... $ (44,232)
=========
Accumulated other comprehensive income (loss)
at March 31, 2004.................................. $ (117,354) $ 11,817 $ 189,091 $ 83,554
========== ======== ========= ========
Net loss for the three months ended June 30, 2004... $ (28,698)
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
before reclassification adjustment during the
three months ended June 30, 2004............. (54,414)
Reclassification adjustment for loss included
in net loss for the three months ended
June 30, 2004................................ 12,905
Income tax benefit for the three months ended
June 30, 2004................................ 13,369
---------- --------
(28,140) (28,140) (28,140)
Available-for-sale investments:
Pre-tax loss on available-for-sale investments
for the three months ended June 30, 2004..... (19,762)
Income tax benefit for the three months ended
June 30, 2004................................ 7,802
--------
(11,960) (11,960) (11,960)
Foreign currency translation loss for the
three months ended June 30, 2004............. (21,399) (21,399) (21,399)
---------- --------- -------- ---------
Total comprehensive loss for the three months ended
June 30, 2004...................................... (90,197)
---------
Total comprehensive loss for the six months ended
June 30, 2004...................................... $(134,429)
=========
Accumulated other comprehensive income (loss)
at June 30, 2004................................... $ (145,494) $ (143) $ 167,692 $ 22,055
========== ======== ========= ========
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Comprehensive
Total Income (Loss)
Accumulated for the Three
Other Months Ended
Foreign Comprehensive March 31, 2003
Cash Flow Currency Income and June 30,
Hedges Translation (Loss) 2003
------------- ----------- -------------- --------------
Accumulated other comprehensive loss at January 1, 2003....... $ (224,414) $ (13,043) $ (237,457)
Net loss for the three months ended March 31, 2003............ $ (52,016)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges before
reclassification adjustment during the three months
ended March 31, 2003................................... 27,827
Reclassification adjustment for loss included in net
loss
for the three months ended March 31, 2003.............. 14,249
Income tax provision for the three months ended
March 31, 2003......................................... (10,927)
------------ ------------
31,149 31,149 31,149
Foreign currency translation gain for the three months
ended March 31, 2003................................... -- 84,062 84,062 84,062
------------ ----------- ------------ -----------
Total comprehensive income for the three months ended
March 31, 2003............................................... $ 63,195
===========
Accumulated other comprehensive income (loss) at March 31,
2003......................................................... $ (193,265) $ 71,019 $ (122,246)
============ =========== ============
Net loss for the three months ended June 30, 2003............. $ (23,366)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges before
reclassification adjustment during the three months
ended June 30, 2003.................................... 47,892
Reclassification adjustment for loss included in net
loss
for the three months ended June 30, 2003............... 11,401
Income tax provision for the three months ended
June 30, 2003.......................................... (28,790)
------------ ------------
30,503 30,503 30,503
Foreign currency translation gain for the three months
ended June 30, 2003.................................... -- 63,494 63,494 63,494
------------ ----------- ------------ -----------
Total comprehensive income for the three months ended
June 30, 2003................................................ 70,631
-----------
Total comprehensive income for the six months ended
June 30, 2003................................................ $ 133,826
===========
Accumulated other comprehensive income (loss) at June 30, 2003 $ (162,762) $ 134,513 $ (28,249)
============ =========== ============
12. Loss per Share
Basic loss per common share were computed by dividing net loss by the
weighted average number of common shares outstanding for the respective periods.
The dilutive effect of the potential exercise of outstanding options to purchase
shares of common stock is calculated using the treasury stock method. The
dilutive effect of the assumed conversion of certain convertible securities into
the Company's common stock is based on the dilutive common share equivalents and
the after tax distribution expense avoided upon conversion. The calculation of
basic loss per common share is shown in the following table (in thousands,
except per share data).
Periods Ended June 30,
--------------------------------------------------------------
2004 2003
----------------------------- -------------------------------
Net Loss Shares EPS Net Loss Shares EPS
---------- ------- -------- --------- -------- --------
THREE MONTHS:
Basic and diluted loss per common share:
Loss before discontinued operations and cumulative
effect of a change in accounting principle.......... $ (28,896) 417,357 $ (0.07) $ (16,375) 381,219 $ (0.04)
Discontinued operations, net of tax.................. 198 -- -- (6,991) -- (0.02)
Cumulative effect of a change in accounting
principle, net of tax............................... -- -- -- -- -- --
--------- -------- -------- --------- ------- -------
Net loss............................................. $ (28,698) 417,357 $ (0.07) $ (23,366) 381,219 $ (0.06)
========= ======== ======== ========= ======= =======
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Periods Ended June 30,
--------------------------------------------------------------
2004 2003
----------------------------- -------------------------------
Net Loss Shares EPS Net Loss Shares EPS
---------- ------- -------- --------- -------- --------
SIX MONTHS:
Basic and diluted loss per common share:
Loss before discontinued operations and cumulative
effect of a change in accounting principle.......... $(122,945) 416,332 $ (0.30) $ (67,914) 381,089 $ (0.18)
Discontinued operations, net of tax.................. 23,055 -- 0.06 (7,997) -- (0.02)
Cumulative effect of a change in accounting
principle, net of tax............................... -- -- -- 529 -- --
--------- -------- ------- --------- ------- -------
Net loss............................................. $ (99,890) 416,332 $ (0.24) $ (75,382) 381,089 $ (0.20)
========= ======== ======== ========= ======= =======
Because of the Company's losses for the three and six months ended June 30,
2004 and 2003, basic shares were also used in the calculations of fully diluted
loss per share, under the guidelines of SFAS No. 128, "Earnings per Share," as
using the basic shares produced the more dilutive effect on the loss per share.
Potentially convertible securities and unexercised employee stock options to
purchase 60,551,462 and 118,701,972 shares of the Company's common stock were
not included in the computation of diluted shares outstanding during the six
months ended June 30, 2004 and 2003, respectively, because such inclusion would
be anti-dilutive.
For the three and six months ended June 30, 2004, approximately 4.0 million
and 13.9 million weighted common shares of the Company's outstanding 4%
convertible senior notes due 2006 were excluded from the diluted EPS
calculations as the inclusion of such shares would have been antidilutive. Due
to repurchases by the Company of these securities during the first quarter of
2004, at June 30, 2004, 4.0 million common shares were potentially issuable upon
the conversion of 100% of these securities then outstanding. The holders have
the right to require the Company to repurchase these securities on December 26,
2004, at a repurchase price equal to the issue price plus any accrued and unpaid
interest, payable at the option of the Company in cash or common shares, or a
combination of cash and common shares.
In connection with the convertible notes payable to Calpine Capital Trust
("Trust I"), Calpine Capital Trust II ("Trust II") and Calpine Capital Trust III
("Trust III"), net of repurchases, there were 15.8 million, 14.1 million and
11.9 million common shares potentially issuable, respectively, that were
excluded from the diluted EPS calculation for the three months ended June 30,
2004. For the six month period then ended, respectively, there were 16.1
million, 14.1 million, and 11.9 million potentially issuable weighted shares
that were excluded from the EPS calculation as their inclusion would be
antidilutive. These notes are convertible at any time at the applicable holder's
option in connection with the conversion of convertible preferred securities
issued by the Trusts, and may be redeemed at any time after their respective
initial redemption date. The Company is required to remarket the convertible
preferred securities issued by Trust I, Trust II and Trust III no later than
November 1, 2004, February 1, 2005 and August 1, 2005, respectively. If the
Company is not able to remarket those securities, it will result in additional
interest costs and an adjusted conversion rate equal to 105% of the average
closing price of our common stock for the five consecutive trading days after
the failed remarketing.
For the three and six months ended June 30, 2004, there were no shares
potentially issuable with respect to the Company's 4.75% Convertible Senior
Notes Due 2023. Upon the occurrence of certain contingencies (generally if the
average trading price as calculated under the prescribed definition exceeds 120%
of $6.50 per share, i.e. $7.80 per share), these securities are convertible at
the holder's option for cash for the face amount and shares of the Company's
common stock for the appreciated value in the Company's common stock over $6.50
per share. Holders have the right to require the Company to repurchase these
securities at various times beginning on November 15, 2009, for the face amount
plus any accrued and unpaid interest and liquidated damages, if any. The
repurchase price is payable at the option of the Company in cash or common
shares, or a combination of both. The Company may redeem these securities at any
time on or after November 22, 2009, in cash for the face amount plus any accrued
and unpaid interest and liquidated damages, if any. Approximately 138.4 million
maximum potential shares are issuable upon conversion of these securities and
are excluded from the diluted EPS calculations as there are currently no shares
contingently issuable due to the Company's quarter end stock price being under
$7.80.
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13. Commitments and Contingencies
Turbines. The table below sets forth future turbine payments for
construction and development projects, as well as for unassigned turbines. It
includes previously delivered turbines, payments and delivery by year for the
remaining 5 turbines to be delivered as well as payment required for the
potential cancellation costs of the remaining 52 gas and steam turbines. The
table does not include payments that would result if the Company were to release
for manufacturing any of these remaining 52 turbines.
Units to
Year Total Be Delivered
- ------------------------------------------ --------- ------------
(In thousands)
July through December 2004................. $ 52,261 5
2005....................................... 21,117 --
2006....................................... 2,706 --
---------- ---
Total................................... $ 76,084 5
========== ===
Litigation
The Company is party to various litigation matters arising out of the
normal course of business, the more significant of which are summarized below.
The ultimate outcome of each of these matters cannot presently be determined,
nor can the liability that could potentially result from a negative outcome be
reasonably estimated presently for every case. The liability the Company may
ultimately incur with respect to any one of these matters in the event of a
negative outcome may be in excess of amounts currently accrued with respect to
such matters and, as a result of these matters, may potentially be material to
the Company's Consolidated Condensed Financial Statements.
Securities Class Action Lawsuits. Since March 11, 2002, fourteen
shareholder lawsuits have been filed against Calpine and certain of its officers
in the United States District Court for the Northern District of California. The
actions captioned Weisz v. Calpine Corp., et al., filed March 11, 2002, and
Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002, are
purported class actions on behalf of purchasers of Calpine stock between March
15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18,
2002, is a purported class action on behalf of purchasers of Calpine stock
between February 6, 2001 and December 13, 2001. The eleven other actions,
captioned Local 144 Nursing Home Pension Fund v. Calpine Corp., Lukowski v.
Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., Laborers Local
1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta
v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp., and Rose v.
Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The
complaints in these eleven actions are virtually identical-- they are filed by
three law firms, in conjunction with other law firms as co-counsel. All eleven
lawsuits are purported class actions on behalf of purchasers of Calpine's
securities between January 5, 2001 and December 13, 2001.
The complaints in these fourteen actions allege that, during the purported
class periods, certain Calpine executives issued false and misleading statements
about Calpine's financial condition in violation of Sections 10(b) and 20(1) of
the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek
an unspecified amount of damages, in addition to other forms of relief.
In addition, a fifteenth securities class action, Ser v. Calpine, et al.,
was filed on May 13, 2002. The underlying allegations in the Ser action are
substantially the same as those in the above-referenced actions. However, the
Ser action is brought on behalf of a purported class of purchasers of Calpine's
8.5% Senior Notes Due February 15, 2011 ("2011 Notes") and the alleged class
period is October 15, 2001 through December 13, 2001. The Ser complaint alleges
that, in violation of Sections 11 and 15 of the Securities Act of 1933, the
Supplemental Prospectus for the 2011 Notes contained false and misleading
statements regarding Calpine's financial condition. This action names Calpine,
certain of its officers and directors, and the underwriters of the 2011 Notes
offering as defendants, and seeks an unspecified amount of damages, in addition
to other forms of relief.
All fifteen of these securities class action lawsuits were consolidated in
the United States District Court for the Northern District of California.
Plaintiffs filed a first amended complaint in October 2002. The amended
complaint did not include the 1933 Act complaints raised in the bondholders'
complaint, and the number of defendants named was reduced. On January 16, 2003,
before the Company's response was due to this amended complaint, plaintiffs
filed a further second complaint. This second amended complaint added three
additional Calpine executives and Arthur Andersen LLP as defendants. The second
amended complaint set forth additional alleged violations of Section 10 of the
Securities Exchange Act of 1934 relating to allegedly false and misleading
statements made regarding Calpine's role in the California energy crisis, the
long term power contracts with the California Department of Water Resources, and
Calpine's dealings with Enron, and additional claims under Section 11 and
-30-
Section 15 of the Securities Act of 1933 relating to statements regarding the
causes of the California energy crisis. The Company filed a motion to dismiss
this consolidated action in early April 2003.
On August 29, 2003, the judge issued an order dismissing, with leave to
amend, all of the allegations set forth in the second amended complaint except
for a claim under Section 11 of the Securities Act relating to statements
relating to the causes of the California energy crisis and the related increase
in wholesale prices contained in the Supplemental Prospectuses for the 2011
Notes.
The judge instructed plaintiff, Julies Ser, to file a third amended
complaint, which he did on October 17, 2003. The third amended complaint names
Calpine and three executives as defendants and alleges the Section 11 claim that
survived the judge's August 29, 2003 order.
On November 21, 2003, Calpine and the individual defendants moved to
dismiss the third amended complaint on the grounds that plaintiff's Section 11
claim was barred by the applicable one-year statute of limitations. On February
4, 2004, the judge denied the Company's motion to dismiss but has asked the
parties to be prepared to file summary judgment motions to address the statute
of limitations issue. The Company filed its answer to the third amended
complaint on February 28, 2004.
In a separate order dated February 4, 2004, the court denied without
prejudice Julies Ser's motion to be appointed lead plaintiff. Mr. Ser
subsequently stated he no longer desired to serve as lead plaintiff. On April 4,
2004, the Policemen and Firemen Retirement System of the City of Detroit ("P&F")
moved to be appointed lead plaintiff, which motion was granted on May 14, 2004.
The Company considers the lawsuit to be without merit and intends to
continue to defend vigorously against these allegations.
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities
class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was
filed on March 11, 2003, against Calpine, its directors and certain investment
banks in state superior court of San Diego County, California. The underlying
allegations in the Hawaii Structural Ironworkers Pension Fund action ("Hawaii
action") are substantially the same as the federal securities class actions
described above. However, the Hawaii action is brought on behalf of a purported
class of purchasers of Calpine's equity securities sold to public investors in
its April 2002 equity offering. The Hawaii action alleges that the Registration
Statement and Prospectus filed by Calpine which became effective on April 24,
2002, contained false and misleading statements regarding Calpine's financial
condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933.
The Hawaii action relies in part on Calpine's restatement of certain past
financial results, announced on March 3, 2003, to support its allegations. The
Hawaii action seeks an unspecified amount of damages, in addition to other forms
of relief.
The Company removed the Hawaii action to federal court in April 2003 and
filed a motion to transfer the case for consolidation with the other securities
class action lawsuits in the United States District Court for the Northern
District of California in May 2003. Plaintiff sought to have the action remanded
to state court, and on August 27, 2003, the United States District Court for the
Southern District of California granted plaintiff's motion to remand the action
to state court. In early October 2003 plaintiff agreed to dismiss the claims it
has against three of the outside directors.
On November 5, 2003, Calpine, the individual defendants and the underwriter
defendants filed motions to dismiss this complaint on numerous grounds. On
February 6, 2004, the court issued a tentative ruling sustaining the Company's
motion to dismiss on the issue of plaintiff's standing. The court found that
plaintiff had not shown that it had purchased Calpine stock "traceable" to the
April 2002 equity offering. The court overruled the Company's motion to dismiss
on all other grounds. On March 12, 2004, after oral argument on the issues, the
court confirmed its February 2, 2004, ruling.
On February 20, 2004, plaintiff filed an amended complaint, and in late
March 2004 the Company and the individual defendants filed answers to this
complaint. On April 9, 2004, the Company and the individual defendants filed
motions to transfer the lawsuit to Santa Clara County Superior Court, which
motions were granted on May 7, 2004. The Company considers this lawsuit to be
without merit and intends to continue to defend vigorously against it.
Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in
the Calpine Corporation Retirement Savings Plan (the "401(k) Plan") filed a
class action lawsuit in the United States District Court for the Northern
District of California. The underlying allegations in this action ("Phelps
action") are substantially the same as those in the securities class actions
described above. However, the Phelps action is brought on behalf of a purported
class of participants in the 401(k) Plan. The Phelps action alleges that various
filings and statements made by Calpine during the class period were materially
false and misleading, and that defendants failed to fulfill their fiduciary
-31-
obligations as fiduciaries of the 401(k) Plan by allowing the 401(k) Plan to
invest in Calpine common stock. The Phelps action seeks an unspecified amount of
damages, in addition to other forms of relief. In May 2003 Lennette Poor-Herena,
another participant in the 401(k) Plan, filed a substantially similar class
action lawsuit as the Phelps action also in the Northern District of California.
Plaintiffs' counsel is the same in both of these actions, and they have agreed
to consolidate these two cases and to coordinate them with the consolidated
federal securities class actions described above. On January 20, 2004, plaintiff
James Phelps filed a consolidated ERISA complaint naming Calpine and numerous
individual current and former Calpine Board members and employees as defendants.
Pursuant to a stipulated agreement with plaintiff, Calpine's response to the
amended complaint is due August 13, 2004. The Company considers this lawsuit to
be without merit and intends to vigorously defend against it.
Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder
filed a derivative lawsuit on behalf of Calpine against its directors and one of
its senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. and
is pending in state superior court of Santa Clara County, California. Calpine is
a nominal defendant in this lawsuit, which alleges claims relating to
purportedly misleading statements about Calpine and stock sales by certain of
the director defendants and the officer defendant. In December 2002 the court
dismissed the complaint with respect to certain of the director defendants for
lack of personal jurisdiction, though plaintiff may appeal this ruling. In early
February 2003 plaintiff filed an amended complaint. In March 2003 Calpine and
the individual defendants filed motions to dismiss and motions to stay this
proceeding in favor of the federal securities class actions described above. In
July 2003 the court granted the motions to stay this proceeding in favor of the
consolidated federal securities class actions described above. The Company
cannot estimate the possible loss or range of loss from this matter. The Company
considers this lawsuit to be without merit and intends to vigorously defend
against it.
Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a
derivative suit in the United States District Court for the Northern District of
California on behalf of Calpine against its directors, captioned Gordon v.
Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to
dismiss the action against certain of the director defendants on the grounds of
lack of personal jurisdiction, as well as to dismiss the complaint in total on
other grounds. In February 2003 plaintiff agreed to stay these proceedings in
favor of the consolidated federal securities class action described above and to
dismiss without prejudice certain director defendants. On March 4, 2003,
plaintiff filed papers with the court voluntarily agreeing to dismiss without
prejudice the claims he had against three of the outside directors. The Company
cannot estimate the possible loss or range of loss from this matter. The Company
considers this lawsuit to be without merit and intends to continue to defend
vigorously against it.
Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, Calpine
sued Automated Credit Exchange ("ACE") in state superior court of Alameda
County, California for negligence and breach of contract to recover reclaim
trading credits, a form of emission reduction credits that should have been held
in Calpine's account with U.S. Trust Company ("US Trust"). Calpine wrote off
$17.7 million in December 2001 related to losses that it alleged were caused by
ACE. Calpine and ACE entered into a Settlement Agreement on March 29, 2002,
pursuant to which ACE made a payment to Calpine of $7 million and transferred to
Calpine the rights to the emission reduction credits to be held by ACE. The
Company recognized the $7 million as income in the second quarter of 2002. In
June 2002 a complaint was filed by InterGen North America, L.P. ("InterGen")
against Anne M. Sholtz, the owner of ACE, and EonXchange, another
Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002.
InterGen alleges it suffered a loss of emission reduction credits from
EonXchange in a manner similar to Calpine's loss from ACE. InterGen's complaint
alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other
Sholtz entities and that ACE and other Sholtz entities should be deemed to be
one economic enterprise and all retroactively included in the EonXchange
bankruptcy filing as of May 6, 2002. By a judgment entered on October 30, 2002,
the bankruptcy court consolidated ACE and the other Sholtz controlled entities
with the bankruptcy estate of EonXchange. Subsequently, the Trustee of
EonXchange filed a separate motion to substantively consolidate Anne Sholtz into
the bankruptcy estate of EonXchange. Although Anne Sholtz initially opposed such
motion, she entered into a settlement agreement with the Trustee consenting to
her being substantively consolidated into the bankruptcy proceeding. The
bankruptcy court entered an order approving Anne Sholtz's settlement agreement
with the Trustee on April 3, 2002. On July 10, 2003, Howard Grobstein, the
Trustee in the EonXchange bankruptcy, filed a complaint for avoidance against
Calpine, seeking recovery of the $7 million (plus interest and costs) paid to
Calpine in the March 29, 2002 Settlement Agreement. The complaint claims that
the $7 million received by Calpine in the Settlement Agreement was transferred
within 90 days of the filing of bankruptcy and therefore should be avoided and
preserved for the benefit of the bankruptcy estate. On August 28, 2003, Calpine
filed its answer denying that the $7 million is an avoidable preference.
Following two settlement conferences, on or about May 21, 2004, Calpine and the
Trustee entered into a Settlement Agreement, whereby Calpine agreed to pay $5.85
-32-
million, which was approved by the Bankruptcy Court on June 16, 2004. The
preference lawsuit will be dismissed with prejudice upon final payment of the
settlement, which will occur on October 1, 2004.
International Paper Company v. Androscoggin Energy LLC. In October 2000
International Paper Company ("IP") filed a complaint in the United States
District Court for the Northern District of Illinois against Androscoggin Energy
LLC ("AELLC") alleging that AELLC breached certain contractual representations
and warranties by failing to disclose facts surrounding the termination,
effective May 8, 1998, of one of AELLC's fixed-cost gas supply agreements. The
Company acquired a 32.3% interest in AELLC as part of the SkyGen transaction
which closed in October 2000. AELLC filed a counterclaim against IP that has
been referred to arbitration that AELLC may commence at its discretion upon
further evaluation. On November 7, 2002, the court issued an opinion on the
parties' cross motions for summary judgment finding in AELLC's favor on certain
matters though granting summary judgment to IP on the liability aspect of a
particular claim against AELLC. The court also denied a motion submitted by IP
for preliminary injunction to permit IP to make payment of funds into escrow
(not directly to AELLC) and require AELLC to post a significant bond.
In mid-April of 2003 IP unilaterally availed itself to self-help in
withholding amounts in excess of $2.0 million as a set-off for litigation
expenses and fees incurred to date as well as an estimated portion of a rate
fund to AELLC. Upon AELLC's amended complaint and request for immediate
injunctive relief against such actions, the court ordered that IP must pay the
approximately $1.2 million withheld as attorneys' fees related to the litigation
as any such perceived entitlement was premature, but deferred to provide
injunctive relief on the incomplete record concerning the offset of $799,000 as
an estimated pass-through of the rate fund. IP complied with the order on April
29, 2003, and tendered payment to AELLC of the approximately $1.2 million. On
June 26, 2003, the court entered an order dismissing AELLC's amended
counterclaim without prejudice to AELLC refiling the claims as breach of
contract claims in a separate lawsuit. On December 11, 2003, the court denied in
part IP's summary judgment motion pertaining to damages. In short, the court:
(i) determined that, as a matter of law, IP is entitled to pursue an action for
damages as a result of AELLC's breach, and (ii) ruled that sufficient questions
of fact remain to deny IP summary judgment on the measure of damages as IP did
not sufficiently establish causation resulting from AELLC's breach of contract
(the liability aspect of which IP obtained a summary judgment in December 2002).
On February 2, 2004, the parties filed a Final Pretrial Order with the court.
The case appears likely scheduled for trial in the third quarter of 2004,
subject to the court's discretion and calendar. The Company believes that it has
adequately reserved for the possible loss, if any, that it may ultimately incur
as a result of this matter.
Pacific Gas and Electric Company v. Calpine Corporation, et al. On July 22,
2003, Pacific Gas and Electric Company ("PG&E") filed with the California Public
Utilities Commission ("CPUC") a Complaint of PG&E and Request for Immediate
Issuance of an Order to Show Cause ("complaint") against Calpine Corporation,
CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas
Company, and Lodi Gas Storage, LLC ("LGS"). The complaint requests the CPUC to
issue an order requiring defendants to show cause why they should not be ordered
to cease and desist from using any direct interconnections between the
facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek
and obtain regulatory approval from the CPUC. The complaint also seeks an order
directing defendants to pay to PG&E any underpayments of PG&E's tariffed
transportation rates and to make restitution for any profits earned from any
business activity related to LGS' direct interconnections to any entity other
than PG&E. The complaint further alleges that various natural gas consumers,
including Calpine affiliated generation projects within California, are engaged
with defendants in the acts complained of, and that the defendants unlawfully
bypass PG&E's system and operate as an unregulated local distribution company
within PG&E's service territory. On August 27, 2003, Calpine filed its answer
and a motion to dismiss. LGS also made similar filings. On October 16, 2003, the
presiding administrative law judge denied the motion to dismiss and on October
24, 2003, issued a Scoping Memo and Ruling establishing a procedural schedule
and set the matter for an evidentiary hearing. On January 15, 2004, Calpine, LGS
and PG&E executed a Settlement Agreement to resolve all outstanding allegations
and claims raised in the complaint. Certain aspects of the Settlement Agreement
are effective immediately and the effectiveness of other provisions is subject
to the approval of the Settlement Agreement by the CPUC. In the event the CPUC
fails to approve the Settlement Agreement, its operative terms and conditions
become null and void. The Settlement Agreement provides, in part, for: 1) PG&E
to be paid $2.7 million; 2) the disconnection of the LGS interconnections with
Calpine; 3) Calpine to obtain PG&E consent or regulatory or other governmental
approval before resuming any sales or exchanges at the Ryer Island Meter
Station; 4) PG&E's withdrawal of its public utility claims against Calpine; and
5) no party admitting any wrongdoing. Accordingly, the presiding administrative
law judge vacated the hearing schedule and established a new procedural schedule
for the filing of the Settlement Agreement. On February 6, 2004, the Settlement
Agreement was filed with the CPUC. The parties were given the opportunity to
submit comments and reply comments on the Settlement Agreement. The CPUC
approved the Settlement Agreement on July 8, 2004, and the $2.7 million was paid
to PG&E on July 15, 2004.
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Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On
November 5, 2003, Panda Energy International, Inc. and certain related parties,
including PLC II, LLC, (collectively "Panda") filed suit against Calpine and
certain of its affiliates in the United States District Court for the Northern
District of Texas, alleging, among other things, that the Company breached
duties of care and loyalty allegedly owed to Panda by failing to correctly
construct and operate the Oneta Energy Center ("Oneta"), which the Company
acquired from Panda, in accordance with Panda's original plans. Panda alleges
that it is entitled to a portion of the profits from Oneta plant and that
Calpine's actions have reduced the profits from Oneta plant thereby undermining
Panda's ability to repay monies owed to Calpine on December 1, 2003, under a
promissory note on which approximately $38.6 million (including interest) is
currently outstanding and past due. The note is collateralized by Panda's
carried interest in the income generated from Oneta, which achieved full
commercial operations in June 2003. The company filed a counterclaim against
Panda Energy International, Inc. (and PLC II, LLC) based on a guaranty, and have
also filed a motion to dismiss as to the causes of action alleging federal and
state securities laws violations. The motion to dismiss is currently pending
before the court. However, at the present time, the Company cannot estimate the
potential loss, if any, that might arise from this matter. The Company considers
Panda's lawsuit to be without merit and intends to defend vigorously against it.
The Company stopped accruing interest income on the promissory note due December
1, 2003, as of the due date because of Panda's default in repayment of the note.
California Business & Professions Code Section 17200 Cases, of which the
lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C.,
et al. This purported class action complaint filed in May 2002 against twenty
energy traders and energy companies, including CES, alleges that defendants
exercised market power and manipulated prices in violation of California
Business & Professions Code Section 17200 et seq., and seeks injunctive relief,
restitution, and attorneys' fees. The Company also has been named in seven other
similar complaints for violations of Section 17200. All seven cases were removed
from the various state courts in which they were originally filed to federal
court for pretrial proceedings with other cases in which the Company is not
named as a defendant. However, at the present time, the Company cannot estimate
the potential loss, if any, that might arise from this matter. The Company
considers the allegations to be without merit, and filed a motion to dismiss on
August 28, 2003. The court granted the motion, and plaintiffs have appealed.
Prior to the motion to dismiss being granted, one of the actions, captioned
Millar v. Allegheny Energy Supply Co., LLP, et al., was remanded to state
superior court of Alameda County, California. On January 12, 2004, CES was added
as a defendant in Millar. This action includes similar allegations to the other
17200 cases, but also seeks rescission of the long-term power contracts with the
California Department of Water Resources.
Upon motion from another newly added defendant, Millar was recently removed
to federal court. It has now been transferred to the same judge that is
presiding over the other Section 17200 cases described above, where it will be
consolidated with such cases for pretrial purposes. The Company anticipates
filing a timely motion for dismissal of Millar as well.
Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy
Services, L.P. before the FERC, filed on December 4, 2001. Nevada Section 206
Complaint. On December 4, 2001, Nevada Power Company ("NPC") and Sierra Pacific
Power Company ("SPPC") filed a complaint with FERC under Section 206 of the
Federal Power Act against a number of parties to their power sales agreements,
including Calpine. NPC and SPPC allege in their complaint, which seeks a refund,
that the prices they agreed to pay in certain of the power sales agreements,
including those signed with Calpine, were negotiated during a time when the
power market was dysfunctional and that they are unjust and unreasonable. The
administrative law judge issued an Initial Decision on December 19, 2002, that
found for Calpine and the other respondents in the case and denied NPC the
relief that it was seeking. In June 2003, FERC rejected the complaint. Some
plaintiffs appealed to the FERC and their request for rehearing was denied. The
matter is pending on appeal before the United States Court of Appeals for the
Ninth Circuit, and is in the pleading stage.
Transmission Service Agreement with Nevada Power. On March 16, 2004, NPC
filed a petition for declaratory order at FERC (Docket No. EL04-90-000) asking
that an order be issued requiring Calpine and Reliant Energy Services, Inc. to
pay for transmission service under their Transmission Service Agreements
("TSAs") with NPC or, if the TSAs are terminated, to pay the lesser of the
transmission charges or a pro rata share of the total cost of NPC's Centennial
Project (approximately $33 million for Calpine). Calpine had previously provided
security to NPC for these costs in the form of a surety bond issued by Fireman's
Fund Insurance Company ("FFIC"). The Centennial Project involves construction of
various transmission facilities in two phases; Calpine's Moapa Energy Center
("MEC") is scheduled to receive service under its TSA from facilities yet to be
constructed in the second phase of the Centennial Project. Calpine has filed a
protest to the petition asserting that Calpine will take service under the TSA
if NPC proceeds to execute a purchase power agreement ("PPA") with MEC based on
its winning bid in the Request for Proposals that NPC conducted in 2003. Calpine
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also has taken the position that if NPC does not execute a PPA with MEC, it will
terminate the TSA and any payment by Calpine would be limited to a pro rata
allocation of costs incurred to date on the second phase of the project
(approximately $4.5 million in total) among the three customers to be served. At
this time, Calpine is unable to predict the final outcome of this proceeding or
its impact on Calpine.
On or about April 27, 2004, NPC alleged to FFIC that Calpine had defaulted
on the TSA and made demand on FFIC for the full amount of the surety bond,
$33,333,333.00. On April 29, 2004, FFIC filed a complaint for declaratory order
in state superior court of Marin County, California in connection with this
demand.
FFIC's complaint asks that an order be issued declaring that it has no
obligation to make payment under the bond. Further, if the court determines that
FFIC does have an obligation to make payment, FFIC asks that an order be issued
declaring that (i) Calpine has an obligation to replace it with funds equal to
the amount of NPC's demand against the bond and (ii) Calpine is obligated to
indemnify and hold FFIC harmless for all loss, costs and fees incurred as a
result of the issuance of the bond. Calpine has filed its answer to the
complaint arguing, among other items, that it did not default on its obligations
under the TSA and therefore NPC is not entitled to make a demand upon the FFIC
bond. At this time, Calpine is unable to predict the outcome of this proceeding
or its impact on Calpine.
Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6,
2002, Calpine Canada Natural Gas Partnership ("Calpine Canada") filed a
complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp.
("Enron Canada") owed it approximately $1.5 million from the sale of gas in
connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron
Canada has not sought bankruptcy relief and has counterclaimed in the amount of
$18 million. Discovery is currently in progress, and the Company believes that
Enron Canada's counterclaim is without merit and intends to vigorously defend
against it.
Jones v. Calpine Corporation. On June 11, 2003, the Estate of Darrell Jones
and the Estate of Cynthia Jones filed a complaint against Calpine in the United
States District Court for the Western District of Washington. Calpine purchased
Goldendale Energy, Inc., a Washington corporation, from Darrell Jones. The
agreement provided, among other things, that upon substantial completion of the
Goldendale facility, Calpine would pay Mr. Jones (i) $6.0 million and (ii) $18.0
million less $0.2 million per day for each day that elapsed between July 1,
2002, and the date of substantial completion. Substantial completion of the
Goldendale facility has not occurred and the daily reduction in the payment
amount has reduced the $18.0 million payment to zero. The complaint alleges that
by not achieving substantial completion by July 1, 2002, Calpine breached its
contract with Mr. Jones, violated a duty of good faith and fair dealing, and
caused an inequitable forfeiture. The complaint seeks damages in an unspecified
amount in excess of $75,000. On July 28, 2003, Calpine filed a motion to dismiss
the complaint for failure to state a claim upon which relief can be granted. The
court granted Calpine's motion to dismiss the complaint on March 10, 2004.
Plaintiffs filed a motion for reconsideration of the decision, which was denied.
Subsequently, on June 7, 2004, plaintiffs filed a notice of appeal. Calpine also
filed a motion to recover attorneys' fees from NESCO, which was recently granted
at a reduced amount. Calpine still, however, expects to make the $6.0 million
payment to the estates when the project is completed.
In addition, the Company is involved in various other claims and legal
actions arising out of the normal course of its business. The Company does not
expect that the outcome of these proceedings will have a material adverse effect
on its financial position or results of operations.
14. Operating Segments
The Company is first and foremost an electric generating company. In
pursuing this single business strategy, it is the Company's long-range objective
to produce from its own natural gas reserves ("equity gas") at a level of up to
25% of its fuel consumption requirements. The Company's oil and gas production
and marketing activity has reached the quantitative criteria to be considered a
reportable segment under SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information." The Company's segments are electric
generation and marketing; oil and gas production and marketing; and corporate
and other activities. Electric generation and marketing includes the
development, acquisition, ownership and operation of power production
facilities, and hedging, balancing, optimization, and trading activity
transacted on behalf of the Company's power generation facilities. Oil and gas
production includes the ownership and operation of gas fields, gathering systems
and gas pipelines for internal gas consumption, third party sales and hedging,
balancing, optimization, and trading activity transacted on behalf of the
Company's oil and gas operations. Corporate activities and other consists
primarily of financing activities, the Company's specialty data center
engineering business, which was divested in the third quarter of 2003 and
general and administrative costs. Certain costs related to company-wide
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functions are allocated to each segment, such as interest expense, distributions
on HIGH TIDES prior to October 1, 2003, and interest income, which are allocated
based on a ratio of segment assets to total assets.
The Company evaluates performance based upon several criteria including
profits before tax. The financial results for the Company's operating segments
have been prepared on a basis consistent with the manner in which the Company's
management internally disaggregates financial information for the purposes of
assisting in making internal operating decisions.
Due to the integrated nature of the business segments, estimates and
judgments have been made in allocating certain revenue and expense items, and
reclassifications have been made to prior periods to present the allocation
consistently.
Electric Oil and Gas
Generation Production
and Marketing and Marketing Corporate and Other Total
---------------------- ------------------ ------------------- ----------------------
2004 2003 2004 2003 2004 2003 2004 2003
---------- ---------- -------- -------- -------- --------- ---------- ----------
(In thousands)
For the three months ended
June 30,
Total revenue from external
customers.................... $2,274,080 $2,124,050 $ 26,069 $ 29,300 $ 14,485 $ 11,958 $2,314,634 $2,165,308
Intersegment revenue.......... -- -- 87,227 96,687 -- -- 87,227 96,687
Segment profit/(loss) before
provision for income taxes... (216,195) 256 13,495 21,727 113,200 (43,083) (89,500) (21,100)
Equipment cancellation and
impairment cost.............. 7 19,222 -- -- -- -- 7 19,222
Electric Oil and Gas
Generation Production
and Marketing and Marketing Corporate and Other Total
---------------------- ------------------ ------------------- ----------------------
2004 2003 2004 2003 2004 2003 2004 2003
---------- ---------- -------- -------- -------- --------- ---------- ----------
(In thousands)
For the six months ended
June 30,
Total revenue from external
customers.................... $4,272,273 $4,261,529 $ 50,651 $ 55,210 $ 34,448 $ 14,501 $4,357,372 $4,331,240
Intersegment revenue.......... -- -- 167,337 223,044 -- -- 167,337 223,044
Segment profit/(loss) before
provision for income taxes... (458,475) (73,165) 33,423 69,533 155,554 (85,878) (269,498) (89,510)
Equipment cancellation and
impairment cost.............. 2,367 19,309 -- -- -- -- 2,367 19,309
Electric Oil and Gas Corporate,
Generation Production Other and
and Marketing and Marketing Eliminations Total
------------- ------------- ------------ -------------
(In thousands)
Total assets:
June 30, 2004....................... $ 24,638,535 $ 1,631,915 $ 1,171,312 $ 27,441,762
December 31, 2003................... $ 24,067,448 $ 1,797,755 $ 1,438,729 $ 27,303,932
Intersegment revenues primarily relate to the use of internally produced
gas for the Company's power plants. These intersegment revenues have been
included in Total Revenue and Income before taxes in the oil and gas production
and marketing reporting segment and eliminated in the Corporate and other
reporting segment.
15. California Power Market
California Refund Proceeding. On August 2, 2000, the California Refund
Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric
Company under Section 206 of the Federal Power Act alleging, among other things,
that the markets operated by the California Independent System Operator
("CAISO") and the California Power Exchange ("CalPX") were dysfunctional. In
addition to commencing an inquiry regarding the market structure, FERC
established a refund effective period of October 2, 2000, to June 19, 2001, for
sales made into those markets.
-36-
On December 12, 2002, the Administrative Law Judge ("ALJ") issued a
Certification of Proposed Finding on California Refund Liability ("December 12
Certification") making an initial determination of refund liability. On March
26, 2003, FERC also issued an order adopting many of the ALJ's findings set
forth in the December 12 Certification (the "March 26 Order"). In addition, as a
result of certain findings by the FERC staff concerning the unreliability or
misreporting of certain reported indices for gas prices in California during the
refund period, FERC ordered that the basis for calculating a party's potential
refund liability be modified by substituting a gas proxy price based upon gas
prices in the producing areas plus the tariff transportation rate for the
California gas price indices previously adopted in the refund proceeding. The
Company believes, based on the available information, that any refund liability
that may be attributable to it will increase modestly, from approximately $6.2
million to $8.4 million, after taking the appropriate set-offs for outstanding
receivables owed by the CalPX and CAISO to Calpine. The Company has fully
reserved the amount of refund liability that by its analysis would potentially
be owed under the refund calculation clarification in the March 26 order. The
final determination of the refund liability is subject to further Commission
proceedings to ascertain the allocation of payment obligations among the
numerous buyers and sellers in the California markets. At this time, the Company
is unable to predict the timing of the completion of these proceedings or the
final refund liability. Thus the impact on the Company's business is uncertain
at this time.
On April 26, 2004, Dynegy Inc. entered into a settlement of the California
Refund Proceeding and other proceedings with California governmental entities
and the three California investor-owned utilities. The California governmental
entities include the Attorney General, the California Public Utilities
Commission ("CPUC"), the California Department of Water Resources ("CDWR"), and
the California Electricity Oversight Board. Also, on April 27, 2004, The
Williams Companies, Inc. ("Williams") entered into a settlement of the
California Refund Proceeding and other proceedings with the three California
investor-owned utilities; previously, Williams had entered into a settlement of
the same matters with the California governmental entities. The Williams
settlement with the California governmental entities was similar to the
settlement that Calpine entered into with the California governmental entities
on April 22, 2002. Calpine's settlement was approved by FERC on March 26, 2004,
in an order which partially dismissed Calpine from the California Refund
Proceeding to the extent that any refunds are owed for power sold by Calpine to
CDWR or any other agency of the State of California. On June 30, 2004, a
settlement conference was convened at the FERC to explore settlements among
additional parties.
FERC Investigation into Western Markets. On February 13, 2002, FERC
initiated an investigation of potential manipulation of electric and natural gas
prices in the western United States. This investigation was initiated as a
result of allegations that Enron and others used their market position to
distort electric and natural gas markets in the West. The scope of the
investigation is to consider whether, as a result of any manipulation in the
short-term markets for electric energy or natural gas or other undue influence
on the wholesale markets by any party since January 1, 2000, the rates of the
long-term contracts subsequently entered into in the West are potentially unjust
and unreasonable. FERC has stated that it may use the information gathered in
connection with the investigation to determine how to proceed on any existing or
future complaint brought under Section 206 of the Federal Power Act involving
long-term power contracts entered into in the West since January 1, 2000, or to
initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding
on its own initiative. On August 13, 2002, the FERC staff issued the Initial
Report on Company-Specific Separate Proceedings and Generic Reevaluations;
Published Natural Gas Price Data; and Enron Trading Strategies (the "Initial
Report") summarizing its initial findings in this investigation. There were no
findings or allegations of wrongdoing by Calpine set forth or described in the
Initial Report. On March 26, 2003, the FERC staff issued a final report in this
investigation (the "Final Report"). The FERC staff recommended that FERC issue a
show cause order to a number of companies, including Calpine, regarding certain
power scheduling practices that may have been be in violation of the CAISO's or
CalPX's tariff. The Final Report also recommended that FERC modify the basis for
determining potential liability in the California Refund Proceeding discussed
above. Calpine believes that it did not violate these tariffs and that, to the
extent that such a finding could be made, any potential liability would not be
material.
Also, on June 25, 2003, FERC issued a number of orders associated with
these investigations, including the issuance of two show cause orders to certain
industry participants. FERC did not subject Calpine to either of the show cause
orders. FERC also issued an order directing the FERC Office of Markets and
Investigations to investigate further whether market participants who bid a
price in excess of $250 per megawatt hour into markets operated by either the
CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may
have violated CAISO and CalPX tariff prohibitions. No individual market
participant was identified. The Company believes that it did not violate the
CAISO and CalPX tariff prohibitions referred to by FERC in this order; however,
the Company is unable to predict at this time the final outcome of this
proceeding or its impact on Calpine.
-37-
CPUC Proceeding Regarding QF Contract Pricing for Past Periods. The
Company's Qualifying Facilities ("QF") contracts with PG&E provide that the CPUC
has the authority to determine the appropriate utility "avoided cost" to be used
to set energy payments for certain QF contracts by determining the short run
avoided cost ("SRAC") energy price formula. In mid-2000 the Company's QF
facilities elected the option set forth in Section 390 of the California Public
Utility Code, which provides QFs the right to elect to receive energy payments
based on the CalPX market clearing price instead of the price determined by
SRAC. Having elected such option, the Company was paid based upon the PX zonal
day-ahead clearing price ("PX Price") from summer 2000 until January 19, 2001,
when the PX ceased operating a day-ahead market. The CPUC has conducted
proceedings (R.99-11-022) to determine whether the PX Price was the appropriate
price for the energy component upon which to base payments to QFs which had
elected the PX-based pricing option. The CPUC at one point issued a proposed
decision to the effect that the PX Price was the appropriate price for energy
payments under the California Public Utility Code but tabled it, and a final
decision has not been issued to date. Therefore, it is possible that the CPUC
could order a payment adjustment based on a different energy price
determination. On April 29, 2004, PG&E, The Utility Reform Network, which is a
consumer advocacy group, and the Office of Ratepayer Advocates, which is an
independent consumer advocacy department of the CPUC, (collectively, the "PG&E
Parties") filed a Motion for Briefing Schedule Regarding True-Up of Payments to
QF Switchers (the "April 29 Motion"). The April 29 Motion requests that the CPUC
set a briefing schedule under the R.99-11-022 to determine refund liability of
the QFs who had switched to the PX Price during the period of June 1, 2000,
until January 19, 2001. The PG&E Parties allege that refund liability be
determined using the methodology that has been developed thus far in the
California Refund Proceeding discussed above. The Company believes that the PX
Price was the appropriate price for energy payments and that the basis for any
refund liability based on the interim determination by FERC in the California
Refund Proceeding is unfounded, but there can be no assurance that this will be
the outcome of the CPUC proceedings.
Geysers Reliability Must Run Section 206 Proceeding. CAISO, California
Electricity Oversight Board, Public Utilities Commission of the State of
California, Pacific Gas and Electric Company, San Diego Gas & Electric Company,
and Southern California Edison (collectively referred to as the "Buyers
Coalition") filed a complaint on November 2, 2001 at the FERC requesting the
commencement of a Federal Power Act Section 206 proceeding to challenge one
component of a number of separate settlements previously reached on the terms
and conditions of "reliability must run" contracts ("RMR Contracts") with
certain generation owners, including Geysers Power Company, LLC, which
settlements were also previously approved by the FERC. RMR Contracts require the
owner of the specific generation unit to provide energy and ancillary services
when called upon to do so by the ISO to meet local transmission reliability
needs or to manage transmission constraints. The Buyers Coalition has asked FERC
to find that the availability payments under these RMR Contracts are not just
and reasonable. Geysers Power Company, LLC filed an answer to the complaint in
November 2001. To date, FERC has not established a Section 206 proceeding. The
outcome of this litigation and the impact on the Company's business cannot be
determined at the present time.
16. Subsequent Events
On July 1, 2004, the Company exchanged 4.2 million shares of Calpine common
stock in privately negotiated transactions for approximately $20.0 million par
value of HIGH TIDES I.
On August 5, 2004, the Company announced that its newly created entity,
Calpine Energy Management ("CEM"), entered into a $250.0 million letter of
credit facility with Deutsche Bank (rated Aa3/AA-) that expires in October 2005.
Deutsche Bank will guarantee CEM's power and gas obligations by issuing letters
of credit. Receivables generated through power sales will serve as collateral to
support the letters of credit. The Company expects the new credit enhancement
structure to improve spark spreads and increase working capital at CES.
The Company is currently evaluating the sale of its natural gas reserves
located in Alberta, Canada, as well as the Company's 25% interest in reserves
owned by the CNG Trust. In addition, the Company is evaluating the sale of
certain of its unidentified U.S. natural gas reserves. Related to the potential
sale of the gas reserves, the Company is working on the restructuring of a major
power contract from a fixed price agreement to a capacity and variable energy
arrangement.
Item 2. Management's Discussion and Analysis ("MD&A") of Financial Condition and
Results of Operations.
In addition to historical information, this report contains 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. We
use words such as "believe," "intend," "expect," "anticipate," "plan," "may,"
"will" and similar expressions to identify forward-looking statements. Such
statements include, among others, those concerning our expected financial
performance and strategic and operational plans, as well as all assumptions,
expectations, predictions, intentions or beliefs about future events. You are
-38-
cautioned that any such forward-looking statements are not guarantees of future
performance and that a number of risks and uncertainties could cause actual
results to differ materially from those anticipated in the forward-looking
statements. Such risks and uncertainties include, but are not limited to, (i)
the timing and extent of deregulation of energy markets and the rules and
regulations adopted on a transitional basis with respect thereto, (ii) the
timing and extent of changes in commodity prices for energy, particularly
natural gas and electricity, and the impact of related derivatives transactions,
(iii) unscheduled outages of operating plants, (iv) unseasonable weather
patterns that reduce demand for power, (v) economic slowdowns that can adversely
affect consumption of power by businesses and consumers, (vi) various
development and construction risks that may delay or prevent commercial
operations of new plants, such as failure to obtain the necessary permits to
operate, failure of third-party contractors to perform their contractual
obligations or failure to obtain project financing on acceptable terms, (vii)
uncertainties associated with cost estimates, that actual costs may be higher
than estimated, (viii) development of lower-cost power plants or of a lower cost
means of operating a fleet of power plants by our competitors, (ix) risks
associated with marketing and selling power from power plants in the evolving
energy market, (x) factors that impact exploitation of oil or gas resources,
such as the geology of a resource, the total amount and costs to develop
recoverable reserves, and legal title, regulatory, gas administration, marketing
and operational factors relating to the extraction of natural gas, (xi)
uncertainties associated with estimates of oil and gas reserves, (xii) the
effects on our business resulting from reduced liquidity in the trading and
power generation industry, (xiii) our ability to access the capital markets on
attractive terms or at all, (xiv) uncertainties associated with estimates of
sources and uses of cash, that actual sources may be lower and actual uses may
be higher than estimated, (xv) the direct or indirect effects on our business of
a lowering of our credit rating (or actions we may take in response to changing
credit rating criteria), including increased collateral requirements, refusal by
our current or potential counterparties to enter into transactions with us and
our inability to obtain credit or capital in desired amounts or on favorable
terms, (xvi) present and possible future claims, litigation and enforcement
actions, (xvii) effects of the application of regulations, including changes in
regulations or the interpretation thereof, and (xviii) other risks identified in
this report. You should also carefully review the risks described in other
reports that we file with the Securities and Exchange Commission, including
without limitation our annual report on Form 10-K for the year ended December
31, 2003, and our quarterly report on Form 10-Q for the three months ended March
31, 2004. We undertake no obligation to update any forward-looking statements,
whether as a result of new information, future developments or otherwise.
We file annual, quarterly and periodic reports, proxy statements and other
information with the SEC. You may obtain and copy any document we file with the
SEC at the SEC's public reference room at 450 Fifth Street, N.W., Washington,
D.C. 20549. You may obtain information on the operation of the SEC's public
reference facilities by calling the SEC at 1-800-SEC-0330. You can request
copies of these documents, upon payment of a duplicating fee, by writing to the
SEC at its principal office at 450 Fifth Street, N.W., Washington, D.C.
20549-1004. The SEC maintains an Internet website at http://www.sec.gov that
contains reports, proxy and information statements, and other information
regarding issuers that file electronically with the SEC. Our SEC filings are
accessible through the Internet at that website.
Our reports on Forms 10-K, 10-Q and 8-K, and amendments to those reports,
are available for download, free of charge, as soon as reasonably practicable
after these reports are filed with the SEC, at our website at www.calpine.com.
The content of our website is not a part of this report. You may request a copy
of our SEC filings, at no cost to you, by writing or telephoning us at: Calpine
Corporation, 50 West San Fernando Street, San Jose, California 95113, attention:
Lisa M. Bodensteiner, Assistant Secretary, telephone: (408) 995-5115. We will
not send exhibits to the documents, unless the exhibits are specifically
requested and you pay our fee for duplication and delivery.
Selected Operating Information
Set forth below is certain selected operating information for our power
plants for which results are consolidated in our Consolidated Condensed
Statements of Operations. Electricity revenue is composed of fixed capacity
payments, which are not related to production, and variable energy payments,
which are related to production. Capacity revenues include, besides traditional
capacity payments, other revenues such as Reliability Must Run and Ancillary
Service revenues. The information set forth under thermal and other revenue
consists of host steam sales and other thermal revenue ( in thousands except
production and pricing data).
-39-
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
Power Plants:
Electricity and steam ("E&S") revenues:
Energy................................................ $ 964,066 $ 714,237 $ 1,896,562 $ 1,529,047
Capacity.............................................. 228,200 220,414 409,664 377,857
Thermal and other..................................... 120,526 111,609 252,452 239,424
------------ ------------ ------------ ------------
Subtotal.............................................. $ 1,312,792 $ 1,046,260 $ 2,558,678 $ 2,146,328
Spread on sales of purchased power(1).................... 51,483 6,086 56,572 7,421
------------ ------------ ------------ ------------
Adjusted E&S revenues (non-GAAP)......................... $ 1,364,275 $ 1,052,346 $ 2,615,250 $ 2,153,749
Megawatt hours produced.................................. 22,082,911 17,518,737 43,131,994 36,622,157
All-in electricity price per megawatt hour generated..... $ 61.78 $ 60.07 $ 60.63 $ 58.81
- ------------
<FN>
(1) From hedging, balancing and optimization activities related to our
generating assets.
</FN>
Set forth below is a table summarizing the dollar amounts and percentages
of our total revenue for the three and six months ended June 30, 2004 and 2003,
that represent purchased power and purchased gas sales for hedging and
optimization and the costs we incurred to purchase the power and gas that we
resold during these periods (in thousands, except percentage data):
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
Total revenue............................................ $ 2,314,634 $ 2,165,308 $ 4,357,372 $ 4,331,240
Sales of purchased power for hedging
and optimization (1).................................... 496,652 744,805 876,680 1,426,089
As a percentage of total revenue......................... 21.5% 34.4% 20.1% 33.0%
Sale of purchased gas for hedging
and optimization........................................ 481,971 328,478 834,708 655,945
As a percentage of total revenue......................... 20.8% 15.2% 19.2% 15.1%
Total cost of revenue ("COR")............................ 2,246,944 1,989,715 4,169,139 3,990,510
Purchased power expense for hedging
and optimization (1).................................... 445,169 738,719 820,108 1,418,668
As a percentage of total COR............................. 19.8% 37.1% 19.7% 35.6%
Purchased gas expense for hedging
and optimization........................................ 453,922 331,122 814,409 648,070
As a percentage of total COR............................. 20.2% 16.6% 19.5% 16.2%
- ------------
<FN>
(1) On October 1, 2003, we adopted on a prospective basis Emerging Issues Task
Force ("EITF") Issue No. 03-11 "Reporting Realized Gains and Losses on
Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
`Held for Trading Purposes' As defined in EITF Issue No. 02-3: "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes
and Contracts Involved in Energy Trading and Risk Management Activities"
("EITF Issue No. 03-11") and netted purchased power expense against sales
of purchased power. See Note 2 of the Notes to Consolidated Financial
Statements for a discussion of our application of EITF Issue No. 03-11.
</FN>
The primary reasons for the significant levels of these sales and costs of
revenue items include: (a) significant levels of hedging, balancing and
optimization activities by our Calpine Energy Services, L.P. ("CES") risk
management organization; (b) particularly volatile markets for electricity and
natural gas, which prompted us to frequently adjust our hedge positions by
buying power and gas and reselling it; (c) the accounting requirements under
Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial
Statements," and EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Asset," under which we show many of our hedging contracts on a
gross basis (as opposed to netting sales and cost of revenue); and (d) rules in
effect associated with the NEPOOL market in New England, which require that all
power generated in NEPOOL be sold directly to the Independent System Operator
("ISO") in that market; we then buy from the ISO to serve our customer
contracts. Generally accepted accounting principles required us to account for
this activity, which applies to three of our merchant generating facilities, as
the aggregate of two distinct sales and one purchase until our prospective
-40-
adoption of EITF Issue No. 03-11 on October 1, 2003. This gross basis
presentation increases revenues but not gross profit. The table below details
the financial extent of our transactions with NEPOOL for all financial periods
prior to the adoption of EITF Issue No. 03-11. Our entrance into the NEPOOL
market began with our acquisition of the Dighton, Tiverton and Rumford
facilities on December 15, 2000.
Three Months Ended Six Months Ended
June 30, 2003 June 30,2003
------------------ ----------------
(In thousands)
Sales to NEPOOL from power we generated............................. $ 75,642 $ 152,540
Sales to NEPOOL from hedging and other activity..................... 22,952 105,963
---------- ----------
Total sales to NEPOOL............................................ $ 98,594 $ 258,503
Total purchases from NEPOOL...................................... $ 76,697 $ 210,865
Overview
Our core business and primary source of revenue is the generation and
delivery of electric power. We provide power to our U.S., Canadian and U.K.
customers through the development and construction, or acquisition, and
operation of efficient and environmentally friendly electric power plants fueled
primarily by natural gas and, to a much lesser degree, by geothermal resources.
We own and produce natural gas and to a lesser extent oil, which we use
primarily to lower our costs of power production and provide a natural hedge of
fuel costs for our electric power plants, but also to generate some revenue
through sales to third parties. We protect and enhance the value of our electric
and gas assets with a sophisticated risk management organization. We also
protect our power generation assets and control certain of our costs by
producing certain of the combustion turbine replacement parts that we use at our
power plants, and we generate revenue by providing combustion turbine parts to
third parties. Finally, we offer services to third parties to capture value in
the skills we have honed in building, commissioning and operating power plants.
Our key opportunities and challenges include:
o preserving and enhancing our liquidity while spark spreads (the
differential between power revenues and fuel costs) are depressed,
o selectively adding new load-serving entities and power users to our
satisfied customer list as we increase our power contract portfolio,
o continuing to add value through prudent risk management and
optimization activities, and
o lowering our costs of production through various efficiency programs.
Since the latter half of 2001, there has been a significant contraction in
the availability of capital for participants in the energy sector. This has been
due to a range of factors, including uncertainty arising from the collapse of
Enron Corp. and a perceived near-term surplus supply of electric generating
capacity. These factors have continued through 2003 and into 2004, during which
decreased spark spreads have adversely impacted our liquidity and earnings.
While we have been able to continue to access the capital and bank credit
markets on attractive terms, we recognize that the terms of financing available
to us in the future may not be attractive. To protect against this possibility
and due to current market conditions, we scaled back our capital expenditure
program to enable us to conserve our available capital resources.
Set forth below are the Results of Operations for the three and six months
ended June 30, 2004 and 2003.
Results of Operations
Three Months Ended June 30, 2004, Compared to Three Months Ended June 30,
2003 (in millions, except for unit pricing information, percentages and MW
volumes).
Revenue
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Total revenue................................................ $ 2,314.6 $ 2,165.3 $ 149.3 6.9%
-41-
The increase in total revenue is explained by category below.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Electricity and steam revenue................................ $ 1,312.8 $ 1,046.3 $ 266.5 25.5%
Sales of purchased power for hedging and optimization........ 496.6 744.8 (248.2) (33.3)%
----------- ----------- ----------
Total electric generation and marketing revenue........... $ 1,809.4 $ 1,791.1 $ 18.3 1.0%
=========== =========== ==========
Electricity and steam revenue increased as we completed construction and
brought into operation 4 new baseload power plants and 2 expansion projects
completed subsequent to June 30, 2003. Average megawatts in operation of our
consolidated plants increased by 26.7% to 24,357 MW while generation increased
by 26.1%. Average realized electric price, before the effects of hedging,
balancing and optimization, decreased from $59.72/MWh in 2003 to $59.45/MWh in
2004.
Sales of purchased power for hedging and optimization decreased in the
three months ended June 30, 2004, due primarily to netting approximately $322.0
of sales of purchased power with purchase power expense in the quarter ended
June 30, 2004, in connection with the adoption of EITF Issue No. 03-11 on a
prospective basis in the fourth quarter of 2003. The decrease was partly offset
by higher realized prices on hedging, balancing and optimization activities.
Without this netting, sales of purchased power would have increased by $73.8 or
9.9%.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Oil and gas sales............................................ $ 26.0 $ 29.3 $ (3.3) (11.3)%
Sales of purchased gas for hedging and optimization.......... 482.0 328.5 153.5 46.7%
----------- ----------- ----------
Total oil and gas production and marketing revenue........ $ 508.0 $ 357.8 $ 150.2 42.0%
=========== =========== ==========
Oil and gas sales are net of internal consumption, which is eliminated in
consolidation. Internal consumption decreased from $96.7 in 2003 to $87.2 in
2004 primarily as a result of lower production following asset sales in October
2003, and again in February 2004, to the Calpine Natural Gas Trust in Canada.
Before intercompany eliminations oil and gas sales decreased from $126.0 in 2003
to $113.2 in 2004.
Sales of purchased gas for hedging and optimization increased during 2004
due to higher volumes and higher prices of natural gas as compared to the same
period in 2003.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Realized gain on power and gas trading transactions, net..... $ 6.3 $ 9.0 $ (2.7) (30.0)%
Unrealized loss on power and gas transactions, net........... (28.9) (7.2) (21.7) 301.4%
----------- ----------- ----------
Mark-to-market activities, net............................ $ (22.6) $ 1.8 $ (24.4) (1,355.5)%
=========== =========== ==========
Mark-to-market activities, which are shown on a net basis, result from
general market price movements against our open commodity derivative positions,
including positions accounted for as trading under EITF Issue No. 02-3, "Issues
Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" ("EITF Issue No. 02-3") and other mark-to-market
activities. These commodity positions represent a small portion of our overall
commodity contract position. Realized revenue represents the portion of
contracts actually settled, while unrealized revenue represents changes in the
fair value of open contracts, and the ineffective portion of cash flow hedges.
-42-
The decrease in mark-to-market activities revenue in the three months ended
June 30, 2004, as compared to the same period in 2003 is due primarily to
unfavorable price movements which reduced the fair values of certain commodity
derivative instruments.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Other revenue................................................ $ 19.8 $ 14.6 $ 5.2 35.6%
Other revenue increased during the three months ended June 30, 2004,
primarily due to an increase of $3.9 of revenue derived from management services
performed by our wholly owned subsidiary Calpine Power Services, LLC ("CPS"),
and an increase of $1.3 of revenue from Thomassen Turbine Systems, ("TTS"),
which we acquired in February 2003.
Cost of Revenue
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Cost of revenue.............................................. $ 2,246.9 $ 1,989.7 $ 257.2 12.9%
The increase in total cost of revenue is explained by category below.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Plant operating expense...................................... $ 223.6 $ 159.6 $ 64.0 40.1%
Transmission purchase expense................................ 14.7 11.3 3.4 30.1%
Royalty expense.............................................. 6.9 6.5 0.4 6.2%
Purchased power expense for hedging and optimization......... 445.2 738.7 (293.5) (39.7)%
----------- ----------- ----------
Total electric generation and marketing expense........... $ 690.4 $ 916.1 $ (225.7) (24.6)%
=========== =========== ==========
Plant operating expense increased due to the addition of 4 new baseload
power plants and 2 expansion projects completed subsequent to June 30, 2003. The
addition of these units resulted in a 26.7% increase in average consolidated
operating capacity. Additionally, major maintenance costs increased by $40.7 as
more plants commissioned in recent years underwent initial major maintenance
work.
Transmission purchase expense increased primarily due to additional power
plants achieving commercial operation subsequent to June 30, 2003.
Royalty expense increased primarily due to an increase in electric revenues
at The Geysers geothermal plants and due to an increase in contingent purchase
price payments to the previous owner of the Texas City Power Plant, which are
based on a percentage of gross revenues at this plant. At The Geysers royalties
are paid mostly as a percentage of geothermal electricity revenues.
Purchased power expense for hedging and optimization decreased during the
three months ended June 30, 2004, as compared to the same period in 2003 due
primarily to netting $322.0 of purchased power expense against sales of
purchased power in the quarter ended June 30, 2004, in connection with the
adoption of EITF Issue No. 03-11 in the fourth quarter of 2003, partly offset by
higher realized prices on hedging, balancing and optimization activities.
-43-
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Oil and gas production expense............................... $ 20.7 $ 22.5 $ (1.8) (8.0)%
Oil and gas exploration expense.............................. 2.7 6.5 (3.8) (58.5)%
Oil and gas operating expense............................. 23.4 29.0 (5.6) (19.3)%
Purchased gas expense for hedging and optimization........... 453.9 331.1 122.8 37.1%
----------- ----------- ----------
Total oil and gas operating and marketing expense....... $ 477.3 $ 360.1 $ 117.2 32.5%
=========== =========== ==========
Oil and gas production expense decreased during the three months ended June
30, 2004, as compared to the same period in 2003 primarily due to lower lease
operating expense primarily due to the sale of properties in the fourth quarter
of 2003 and the first quarter in 2004.
Oil and gas exploration expense decreased primarily as a result of a
decrease in dry hole cost.
Purchased gas expense for hedging and optimization increased during the
three months ended June 30, 2004, due to higher volumes and higher prices for
natural gas as compared to the same period in 2003.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Fuel expense
Cost of oil and gas burned by power plants................. $ 886.2 $ 535.6 $ 350.6 65.5%
Recognized (gain) loss on gas hedges....................... (18.4) 3.8 (22.2) (584.2)%
----------- ----------- ----------
Total fuel expense...................................... $ 867.8 $ 539.4 $ 328.4 60.9%
=========== =========== ==========
Cost of oil and gas burned by power plants increased during the three
months ended June 30, 2004 as compared to the same period in 2003 due to a 32%
increase in gas consumption and 22% higher prices excluding the effects of
hedging, balancing and optimization.
We recognized a gain on gas hedges during the three months ended June 30,
2004, as compared to a loss during the same period in 2003 due to favorable gas
price movements against our gas financial instrument positions.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Depreciation, depletion and amortization expense............. $ 161.8 $ 139.0 $ 22.8 16.4%
Depreciation, depletion and amortization expense increased primarily due to
the additional power facilities in consolidated operations subsequent to June
30, 2003.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Operating lease expense...................................... $ 27.0 $ 28.2 $ (1.2) (4.3)%
Operating lease expense decreased from the prior year as the King City
lease was restructured in May 2004 and began to be accounted for as a capital
lease at that point. Therefore, we began to cease incurring operating lease
expense on that lease and instead began to incur depreciation and interest
expense.
-44-
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Other cost of revenue........................................ $ 22.6 $ 6.9 $ 15.7 227.5%
Other cost of revenue increased during the three months ended June 30,
2004, as compared to the same period in 2003 due primarily to $1.1 of additional
expense from Power Systems Manufacturing, LLC ("PSM") and $8.0 of amortization
expense incurred from the adoption of Derivatives Implementation Group ("DIG")
Issue No. C20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly
and Closely Related in Paragraph 10(b) regarding Contracts with a Price
Adjustment Feature." In the fourth quarter of 2003, we recorded a pre-tax
mark-to-market gain of $293.4 as the cumulative effect of a change in accounting
principle. This gain is amortized as expense over the respective lives of the
two power sales contracts from which the mark-to-market gains arose.
Additionally, we incurred $3.8 of higher expenses at CPS, and we incurred $2.5
of insurance expense in our captive insurance company related to a property
claim at the Acadia project.
(Income)/Expenses
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Loss (income) from unconsolidated investments in
power projects.............................................. $ 0.7 $ (59.4) $ 60.1 (101.2)%
During the three months ended June 30, 2003, a $52.8 gain on the
termination of the tolling arrangement with Aquila Merchant Services, Inc. was
recognized on the Acadia Power Plant. Also, we recognized $4.0 less income on
the Aries investment, which we began to consolidate in March 2004 when we
purchased the remaining 50% interest from Aquila.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Equipment cancellation and asset impairment cost............. $ -- $ 19.2 $ (19.2) (100.0)%
Equipment cancellation and asset impairment charge decreased during the
three months ended June 30, 2004, as compared to the same period in 2003
primarily as a result of a loss recognized in 2003 of $17.2 in connection with
the sale of two turbines and also commitment cancellation costs and storage and
suspension costs related to unassigned equipment in 2003.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Project development expense.................................. $ 4.0 $ 6.1 $ (2.1) (34.4)%
Project development expense decreased during the three months ended June
30, 2004, primarily due to the write-off in 2003 of $3.4 of costs on the
canceled Stony Brook expansion project.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Research and development expense............................. $ 5.1 $ 2.5 $ 2.6 104%
-45-
Research and development expense increased during the three months ended
June 30, 2004, as compared to the same period in 2003 primarily due to increased
personnel expenses related to new research and development programs at our PSM
subsidiary.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Sales, general and administrative expense.................... $ 61.0 $ 53.7 $ 7.3 13.6%
Sales, general and administrative expense increased during the three months
ended June 30, 2004, primarily due to an increase in employee, consulting, rent,
insurance and other professional fees. Over half of the variance is directly
attributable to the Sarbanes-Oxley Section 404 internal controls project and
audit work related thereto.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Interest expense............................................. $ 279.7 $ 148.9 $ 130.8 87.8%
Interest expense increased partially as a result of new plants that entered
commercial operations (at which point capitalization of interest expense
ceases). Interest capitalized decreased from $116.5 for the three months ended
June 30, 2003, to $102.2 for the three months ended June 30, 2004. The remaining
increase relates to a 12% increase in average indebtedness excluding the effect
of the deconsolidation of the Calpine Capital Trusts, an increase in the
amortization of terminated interest rate swaps and the recording of interest
expense on debt to the three Calpine Capital Trusts due to the adoption of FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities, an
interpretation of ARB 51" ("FIN 46") prospectively on October 1, 2003. See Note
2 of the Notes to Consolidated Condensed Financial Statements for a discussion
of our adoption of FIN 46. We expect that interest expense will continue to
increase and the amount of interest capitalized will decrease in future periods
as our plants in construction are completed. Finally, our average interest rate
increased by approximately 1.4% due to refinancings, such as the CalGen
facilities, at higher rates.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Distributions on Trust Preferred Securities.................. $ -- $ 15.7 $ (15.7) (100)%
As a result of the deconsolidation of the three Calpine Capital Trusts upon
adoption of FIN 46 as of October 1, 2003, the distributions paid on the Trust
Preferred Securities during the three months ended June 30, 2004, were no longer
recorded on our books and were replaced prospectively by interest expense on our
debt to the Calpine Capital Trusts.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Interest (income)............................................ $ (9.9) $ (9.0) $ (0.9) 10.0%
Interest (income) increased during the three months ended June 30, 2004,
due to an increase in cash and equivalents and restricted cash balances as
compared to the same period in 2003.
-46-
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Minority interest expense.................................... $ 4.7 $ 5.3 $ (0.6) (11.3)%
Minority interest expense decreased during the three months ended June 30,
2004, as compared to the same period in 2003 primarily due to a change in
accounting for the preferred interest at King City under SFAS No. 150 to debt
with interest expense instead of minority interest expense prior to the adoption
of SFAS No. 150.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
(Income) from repurchases of various issuances of debt....... $ (2.6) $ (6.8) $ 4.2 (61.8)%
Income from repurchases of various issuances of debt during the three
months ended June 30, 2004, decreased primarily as a result of $2.3 of higher
deferred financing cost write-offs associated with repurchases and due to the
fact that in 2003 senior notes repurchased were trading at a higher discount to
face value.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Other expense (income)....................................... $ (185.6) $ 20.5 $ (206.1) (1,005.4)%
Other income was $206.1 higher in the three months ended June 30, 2004,
compared to the prior year due primarily due to pre-tax income in the amount of
$171.5 associated with the restructuring of a power purchase agreement for our
Newark and Parlin power plants and the sale of a wholly owned subsidiary of CES,
Utility Contract Funding II ("UCF"), net of transaction costs and the write-off
of unamortized deferred financing costs, $16.4 pre-tax gain from the
restructuring of a long-term gas supply contract, and a $12.3 pre-tax gain from
the King City restructuring transaction related to the sale of our debt
securities that had served as collateral under the King City lease, net of
transaction costs.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Benefit for income taxes..................................... $ (60.6) $ (4.7) $ (55.9) 1,189.4%
For the three months ended June 30, 2004, the effective rate increased to
68% as compared to 22% for the three months ended June 30, 2003. This effective
rate increase is due to the consideration of estimated full year earnings in
estimating, and truing up to on a year-to-date basis, the annual effective rate
and due to the effect of significant permanent items.
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Discontinued operations, net of tax.......................... $ 0.2 $ (7.0) $ (7.2) (102.9)%
During the three months ended June 30, 2003, discontinued operations
activity included the effects of our sale of our 50% interest in the Lost Pines
1 Energy Center, the sale of our Alvin South Field oil and gas assets and the
sale of our specialty data center engineering business. The sale of the Lost
Pines 1 Energy Center closed in January 2004.
-47-
Three Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Net loss..................................................... $ (28.7) $ (23.4) $ (5.3) 22.6%
We recorded a net loss of $28.7 for the three months ended June 30, 2004,
compared to a net loss of $23.4 for the same period in 2003, as gross profit
decreased by $107.9, or 61%, to $67.7. The gross profit decrease is the result
of lower per megawatt-hour spark spreads realized during the three months ended
June 30, 2004, and additional costs associated with new power plants coming on
line. For the three months ended June 30, 2004, we generated 22.1 million
megawatt-hours, which equated to a baseload capacity factor of 47%, and realized
an average spark spread of $21.91 per megawatt-hour. For the same period in
2003, we generated 17.5 million megawatt-hours, which equated to a capacity
factor of 48%, and realized an average spark spread of $26.93 per megawatt-hour.
In the quarter ended June 30, 2004, we netted approximately $322.0 of sales of
purchased power for hedging and optimization with purchased power expense. This
was due to the adoption on October 1, 2003, on a prospective basis, of new
accounting rules related to presentation of non-trading derivative activity.
Without this netting, total revenue would have grown by approximately 21.8%
versus 6.9% as reported. In the second quarter of 2004, as compared to the same
period in 2003, generation did not increase commensurately with new average
capacity coming on line (lower baseload capacity factor). Because of that and
due to lower spark spreads per MWh, our spark spread margins did not keep pace
with the additional operating and depreciation costs associated with the new
capacity. Additional increases in power plant costs for the three months ended
June 30, 2004, as compared to the three months ended June 30, 2003, include a
$22.8 increase in depreciation expense and a $64.0 increase in plant operating
expense. Also, during the three months ended June 30, 2004, financial results
were affected by a $115.1 increase in interest expense and distributions on
trust preferred securities, as compared to the same period in 2003. This
occurred as a result of higher debt balances, higher average interest rates and
lower capitalization of interest expense as new plants entered commercial
operation. Other income was $206.1 higher in the three months ended June 30,
2004, for the reasons explained above. The results for the three months ended
June 30, 2003, included a gain of approximately $0.10 per share, or $52.8, in
connection with terminating a tolling arrangement with a unit of Aquila on the
Acadia facility.
Six Months Ended June 30, 2004, Compared to Six Months Ended June 30, 2003
(in millions, except for unit pricing information, percentages and MW volumes).
Revenue
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Total revenue................................................ $ 4,357.4 $ 4,331.2 $ 26.2 0.6%
The increase in total revenue is explained by category below.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Electricity and steam revenue................................ $ 2,558.7 $ 2,146.3 $ 412.4 19.2%
Sales of purchased power for hedging and optimization........ 876.7 1,426.1 (549.4) (38.5)%
----------- ----------- ----------
Total electric generation and marketing revenue........... $ 3,435.4 $ 3,572.4 $ (137.0) (3.8)%
=========== =========== ==========
Electricity and steam revenue increased as we completed construction and
brought into operation 4 new baseload power plants and 2 expansion projects
completed subsequent to June 30, 2003. Average megawatts in operation of our
consolidated plants increased by 23.9% to 23,134 MW while generation increased
by 17.8%. The increase in generation lagged behind the increase in average MW in
operation as our baseload capacity factor dropped to 48% in the six months ended
June 30, 2004, from 52% in the six months ended June 30, 2003, primarily due to
the increased occurrence of unattractive off-peak market spark spreads in
certain areas reflecting mild weather in the first quarter of 2004 and
-48-
oversupply conditions which are expected to gradually work off over the next
several years. This caused us to cycle off certain of our merchant plants
without contracts in off-peak hours. Average realized electric price, before the
effects of hedging, balancing and optimization, increased from $58.61/MWh in
2003 to $59.32/MWh in 2004.
Sales of purchased power for hedging and optimization decreased in the six
months ended June 30, 2004, due primarily to netting approximately $692.5 of
sales of purchased power with purchase power expense in the quarter ended June
30, 2004, in connection with the adoption of EITF Issue No. 03-11 on a
prospective basis in the fourth quarter of 2003 partly offset by higher volumes
and higher realized prices on hedging, balancing and optimization activities.
Without this netting, sales of purchased power would have increased by $143.1 or
10.0%.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Oil and gas sales............................................ $ 50.7 $ 55.2 $ (4.5) (8.2)%
Sales of purchased gas for hedging and optimization.......... 834.7 656.0 178.7 27.2%
----------- ----------- ----------
Total oil and gas production and marketing revenue........ $ 885.4 $ 711.2 $ 174.2 24.4%
=========== =========== ==========
Oil and gas sales are net of internal consumption, which is eliminated in
consolidation. Internal consumption decreased primarily as a result of lower
production following asset sales in October 2003 and again in February 2004 to
the Calpine Natural Gas Trust in Canada, from $223.0 in 2003 to $167.3 in 2004.
Before intercompany eliminations, oil and gas sales decreased by 21.6% or $60.2
to $218.0 in 2004 from $278.2 in 2003.
Sales of purchased gas for hedging and optimization increased during 2004
due to higher volumes and higher prices of natural gas as compared to the same
period in 2003.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Realized gain on power and gas trading transactions, net..... $ 23.8 $ 30.3 $ (6.5) (21.5)%
Unrealized loss on power and gas transactions, net........... (33.9) (8.0) (25.9) 323.8%
----------- ----------- ----------
Mark-to-market activities, net............................ $ (10.1) $ 22.3 $ (32.4) (145.3)%
=========== =========== ==========
Mark-to-market activities, which are shown on a net basis, result from
general market price movements against our open commodity derivative positions,
including positions accounted for as trading under EITF Issue No. 02-3, "Issues
Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" ("EITF Issue No. 02-3") and other mark-to-market
activities. These commodity positions represent a small portion of our overall
commodity contract position. Realized revenue represents the portion of
contracts actually settled, while unrealized revenue represents changes in the
fair value of open contracts, and the ineffective portion of cash flow hedges.
The decrease in mark-to-market activities revenue in the six months ended
June 30, 2004, as compared to the same period in 2003 is due primarily to
unfavorable price movements which reduced the fair values of certain commodity
derivative instruments.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Other revenue................................................ $ 46.7 $ 25.4 $ 21.3 83.9%
Other revenue increased during the six months ended June 30, 2004,
primarily due to an increase of $13.5 of revenue from TTS, which we acquired in
February 2003, and an increase of $5.3 of revenue from CPS.
-49-
Cost of Revenue
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Cost of revenue.............................................. $ 4,169.1 $ 3,990.5 $ 178.6 4.5%
The increase in total cost of revenue is explained by category below.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Plant operating expense...................................... $ 399.5 $ 321.6 $ 77.9 24.2%
Transmission purchase expense................................ 31.1 20.2 10.9 54.0%
Royalty expense.............................................. 12.8 11.8 1.0 8.5%
Purchased power expense for hedging and optimization......... 820.1 1,418.6 (598.5) (42.2)%
----------- ----------- ----------
Total electric generation and marketing expense........... $ 1,263.5 $ 1,772.2 $ (508.7) (28.7)%
=========== =========== ==========
Plant operating expense increased due to 4 new baseload power plants and 2
expansion projects completed subsequent to June 30, 2003. The addition of these
units resulted in a 23.9% increase in average consolidated operating capacity.
Additionally, major maintenance costs increased by $44.3 as more plants
commissioned in recent years underwent initial major maintenance work.
Transmission purchase expense increased primarily due to additional power
plants achieving commercial operation subsequent to June 30, 2003.
Approximately 71% of the first half of 2004 royalty expense is attributable
to royalties paid to geothermal property owners at The Geysers, mostly as a
percentage of geothermal electricity revenues. The increase in royalty expense
in the first half of 2004 was due primarily to an increase in the accrual of
contingent purchase price payments to the previous owners of the Texas City and
Clear Lake Power Plants based on a percentage of gross revenues at these two
plants.
Purchased power expense for hedging and optimization decreased during the
six months ended June 30, 2004, as compared to the same period in 2003 due
primarily to netting $692.5 of purchased power expense against sales of
purchased power in the quarter ended June 30, 2004, in connection with the
adoption of EITF Issue No. 03-11 in the fourth quarter of 2003, partly offset by
higher volumes and higher realized prices on hedging, balancing and optimization
activities.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Oil and gas production expense............................... $ 41.4 $ 45.8 $ (4.4) (9.6)%
Oil and gas exploration expense.............................. 4.4 8.9 (4.5) (50.6)%
Oil and gas operating expense.............................. 45.8 54.7 (8.9) (16.3)%
Purchased gas expense for hedging and optimization........... 814.4 648.1 166.3 25.7%
----------- ----------- ----------
Total oil and gas operating and marketing expense....... $ 860.2 $ 702.8 $ 157.4 22.4%
=========== =========== ==========
Oil and gas production expense decreased during the six months ended June
30, 2004, as compared to the same period in 2003 primarily due to lower lease
operating expense primarily due to the sale of properties in the fourth quarter
of 2003.
Oil and gas exploration expense decreased primarily as a result of a
decrease in dry hole costs.
Purchased gas expense for hedging and optimization increased during the six
months ended June 30, 2004, due to higher volumes and higher prices of natural
gas as compared to the same period in 2003.
-50-
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Fuel expense
Cost of oil and gas burned by power plants................. $ 1,648.3 $ 1,179.0 $ 469.3 39.8%
Recognized (gain) loss on gas hedges....................... (17.8) (4.2) (13.6) 323.8%
----------- ----------- ----------
Total fuel expense...................................... $ 1,630.5 $ 1,174.8 $ 455.7 38.8%
=========== =========== ==========
Cost of oil and gas burned by power plants increased during the six months
ended June 30, 2004 as compared to the same period in 2003 due to an 27%
increase in gas consumption and 9% higher prices for gas excluding the effects
of hedging, balancing and optimization.
We recognized a larger gain on gas hedges during the six months ended June
30, 2004, as compared to the same period in 2003 due to favorable gas price
movements relative to our gas financial instrument positions.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Depreciation, depletion and amortization expense............. $ 311.2 $ 272.8 $ 38.4 14.1%
Depreciation, depletion and amortization expense increased primarily due to
the additional power facilities in consolidated operations subsequent to June
30, 2003.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Operating lease expense...................................... $ 54.8 $ 55.9 $ (1.1) (2.0)%
Operating lease expense decreased from the prior year as the King City
lease was restructured in May 2004 and began to be accounted for as a capital
lease at that point. Therefore, we stopped incurring operating lease expense on
that lease and instead began to incur depreciation and interest expense.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Other cost of revenue........................................ $ 49.0 $ 12.1 $ 36.9 305.0%
Other cost of revenue increased during the six months ended June 30, 2004,
as compared to the same period in 2003 due primarily to $11.0 of additional
expense from TTS and $16.8 of amortization expense incurred from the adoption of
Derivatives Implementation Group ("DIG") Issue No. C20, "Scope Exceptions:
Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph
10(b) regarding Contracts with a Price Adjustment Feature." In the fourth
quarter of 2003, we recorded a pre-tax mark-to-market gain of $293.4 as the
cumulative effect of a change in accounting principle. This gain is amortized as
expense over the respective lives of the two power sales contracts from which
the mark-to-market gains arose. Additionally, we incurred $5.3 higher costs at
CPS due to a higher level of activity in 2004.
-51-
(Income)/Expenses
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
(Income) from unconsolidated investments in
power projects.............................................. $ (1.8) $ (64.5) $ 62.7 (97.2)%
During the six months ended June 30, 2003, a $52.8 gain on the termination
of the tolling arrangement with Aquila Merchant Services, Inc. was recognized on
the Acadia Power Plant. Also, in 2004 we recognized $6.4 less income on the
Acadia investment, and $3.5 more loss from the Aries investment, which we began
to consolidate in March 2004 when we purchased the remaining 50% interest from
Aquila. In 2004, we recognized $2.6 of income on our interest in the Calpine
Natural Gas Trust in Canada which was formed after June 30, 2003. This was
offset by not having any income on the Gordonsville investment in 2004, as we
sold our interests in this facility in November 2003. In the first half of 2003
we recognized $3.2 million of income on Gordonsville.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Equipment cancellation and asset impairment cost............. $ 2.4 $ 19.3 $ (16.9) (87.6)%
Equipment cancellation and asset impairment charge decreased during the six
months ended June 30, 2004, as compared to the same period in 2003 as a result
of a loss recognized in 2003 of $17.2 from the sale of two turbines. In 2004 we
incurred costs in connection with the termination of a purchase contract for
heat recovery steam generator components.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Project development expense.................................. $ 11.7 $ 11.2 $ 0.5 4.5%
Project development expense increased during the six months ended June 30,
2004, partly due to higher costs associated with cancelled projects.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Research and development expense............................. $ 8.9 $ 4.9 $ 4.0 81.6%
Research and development expense increased during the six months ended June
30, 2004, as compared to the same period in 2003 primarily due to increased
personnel expenses related to new research and development programs at our PSM
subsidiary.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Sales, general and administrative expense.................... $ 118.2 $ 97.4 $ 20.8 21.4%
Sales, general and administrative expense increased during the six months
ended June 30, 2004, primarily due to an increase in employee, consulting, rent,
insurance and other professional fees. Nearly a third of the variance is
directly attributable to the Sarbanes-Oxley Section 404 internal control project
and related audit work.
-52-
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Interest expense............................................. $ 534.5 $ 291.8 $ 242.7 83.2%
Interest expense increased partially as a result of new plants that entered
commercial operations (at which point capitalization of interest expense
ceases). Interest capitalized decreased from $235.0 for the six months ended
June 30, 2003, to $210.7 for the six months ended June 30, 2004. Additionally,
we incurred approximately $12.5 in accelerated amortization of deferred
financing costs due to the early refinancing of the CCFC II debt on March 23,
2004. The remaining increase relates to a 12% increase in average indebtedness
due partially to the deconsolidation of the Calpine Capital Trusts and the
recording of debt to the Calpine Capital Trusts due to the adoption of FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities, an
interpretation of ARB 51" ("FIN 46") prospectively on October 1, 2003. See Note
2 of the Notes to Consolidated Condensed Financial Statements for a discussion
of our adoption of FIN 46. We expect that interest expense will continue to
increase and the amount of interest capitalized will decrease in future periods
as our plants in construction are completed. And finally, our average interest
rate increased by approximately 1.2% due to refinancings, such as the CalGen
facilities, at higher rates.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Distributions on Trust Preferred Securities.................. $ -- $ 31.3 $ (31.3) (100)%
As a result of the deconsolidation of the Calpine Capital Trusts upon
adoption of FIN 46 as of October 1, 2003, the distributions paid on the Trust
Preferred Securities during the six months ended June 30, 2004, were no longer
recorded on our books and were replaced prospectively by interest expense on our
debt to the Calpine Capital Trusts.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Interest (income)............................................ $ (21.9) $ (17.0) $ (4.9) 28.8%
Interest (income) increased during the six months ended June 30, 2004, due
to an increase in cash and equivalents and restricted cash balances as compared
to the same period in 2003.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Minority interest expense.................................... $ 13.2 $ 7.6 $ 5.6 73.7%
Minority interest expense increased during the six months ended June 30,
2004, as compared to the same period in 2003 primarily due to an increase of
$6.7 of minority interest expense associated with the Calpine Power Limited
Partnership ("CLP"), which is 70% owned by CPIF. During 2003, as a result of a
secondary offering of Calpine's interests in the Calpine Income Fund ("CFIF"),
Calpine decreased its ownership interests in CLP to 30%, thus increasing
minority interest expense.
-53-
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
(Income) from repurchase of various issuances of debt........ $ (3.4) $ (6.8) $ 3.4 (50.0)%
Income from repurchases of various issuances of debt during the six months
ended June 30, 2004, decreased primarily as a result of $7.6 of higher deferred
financing cost write-offs associated with repurchases.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Other expense (income)....................................... $ (204.0) $ 55.1 $ (259.1) (470.2)%
Other income increased by $259.1 during the six months ended June 30, 2004,
as compared to the same period in 2003, primarily due to pre-tax income in the
amount of $171.5 associated with the restructuring of a power purchase agreement
for our Newark and Parlin power plants and the sale of UCF, net of transaction
costs and the write-off of unamortized deferred financing costs, $16.4 pre-tax
gain from the restructuring of a long-term gas supply contract net of
transaction costs, and a $12.3 pre-tax gain from the King City restructuring
transaction related to the sale of the Company's debt securities that had served
as collateral under the King City lease, net of transaction costs. Also, during
the six months ended June 30, 2004, foreign currency transaction gains were $4.8
compared to a loss of $44.3 in the corresponding period in 2003.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Benefit for income taxes..................................... $ (146.0) $ (21.6) $ (124.4) 575.9%
For the six months ended June 30, 2004, the effective rate increased to 54%
as compared to 24% for the six months ended June 30, 2003. This effective rate
variance is due to the consideration of estimated year-end earnings in
estimating the annual effective rate and due to the effect of significant
permanent items.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Discontinued operations, net of tax.......................... $ 23.1 $ (8.0) $ 31.1 (388.8)%
In the first half of 2004, our discontinued operations was comprised
primarily of the gain from the sale of our Lost Pines 1 Power Project. During
the six months ended June 30, 2003, discontinued operations activity included
the effects of our sale of our 50% interest in the Lost Pines 1 Energy Center,
the sale of our Alvin South Field oil and gas assets and the sale of our
specialty data center engineering business, reflecting the soft market for data
centers for the foreseeable future.
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Cumulative effect of a change in accounting principle,
net of tax.................................................. $ -- $ (0.5) $ 0.5 100.0%
The cumulative effect of a change in accounting principle, net of tax
effect in 2003 resulted from adopting SFAS No. 143, "Accounting for Asset
Retirement Obligations."
-54-
Six Months Ended
June 30,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- ------------
Net loss..................................................... $ (99.9) $ (75.4) $ (24.5) 32.5%
We recorded a net loss of $99.9 for the six months ended June 30, 2004,
compared to a net loss of $75.4 for the six months ended June 30, 2003. Gross
profit decreased by $152.5, or 45%, to $188.2. This decrease is the result of
lower per megawatt-hour spark spreads realized during the six months ended June
30, 2004, and additional costs associated with new power plants coming on line.
For the six months ended June 30, 2004, we generated 43.1 million
megawatt-hours, which equated to a capacity factor of 48% and realized an
average spark spread of $21.49 per megawatt-hour. For the same period in 2003,
we generated 36.6 million megawatt-hours, which equated to a capacity factor of
52%, and realized an average spark spread of $24.83 per megawatt-hour. During
the first six months of 2004, as compared to the same period in 2003, generation
did not increase commensurately with new average capacity coming on line (lower
baseload capacity factor). Because of that and due to lower spark spreads per
MWh, our spark spread margins did not keep pace with the additional operating
and depreciation costs associated with the new capacity. Additional increases in
power plant costs for the six months ended June 30, 2004, as compared to the six
months ended June 30, 2003, include a $38.4 increase in depreciation expense, a
$77.9 increase in plant operating expense and a $10.9 increase in transmission
purchase expense. Also, during the six months ended June 30, 2004, financial
results were affected by a $211.3 increase in interest expense and distributions
on trust preferred securities, as compared to the first six months of 2003. This
occurred as a result of higher debt balances, higher average interest rates and
lower capitalization of interest expense as new plants entered commercial
operation. Other income increased $259.1 during the six months ended June 30,
2004, for the reasons explained above.
Liquidity and Capital Resources
Our business is capital intensive. Our ability to capitalize on growth
opportunities is dependent on the availability of capital on attractive terms.
The availability of such capital in today's environment is uncertain. To date,
we have obtained cash from our operations; borrowings under our term loan and
revolving credit facilities; issuance of debt, equity, trust preferred
securities and convertible debentures; proceeds from sale/leaseback
transactions; sale or partial sale of certain assets; contract monetizations and
project financings. We have utilized this cash to fund our operations, service
or prepay debt obligations, fund acquisitions, develop and construct power
generation facilities, finance capital expenditures, support our hedging,
balancing, optimization and trading activities at CES, and meet our other cash
and liquidity needs. Our strategy is also to reinvest our cash from operations
into our business development and construction program or to use it to reduce
debt, rather than to pay cash dividends. As discussed below, we have a
liquidity-enhancing program underway for funding the completion of our current
construction portfolio, for refinancing and for general corporate purposes.
Our $2.5 billion secured revolving construction financing facility through
our wholly owned subsidiary Calpine Construction Finance Company II, LLC ("CCFC
II") (renamed Calpine Generating Company, LLC ("CalGen")) was scheduled to
mature in November 2004, requiring us to refinance this indebtedness. As of
December 31, 2003, there was $2.3 billion outstanding under this facility
including $53.2 million of letters of credit. On March 23, 2004, CalGen
completed a secured institutional term loan and secured note financing, which
replaced the old CCFC II facility. We realized total proceeds from the financing
in the amount of $2.4 billion, before transaction costs and fees.
The holders of our 4% Convertible Senior Notes Due 2006 ("2006 Convertible
Senior Notes") have a right to require us to repurchase them at 100% of their
principal amount plus any accrued and unpaid interest on December 26, 2004. We
can effect the repurchase with cash, shares of Calpine stock or a combination of
the two. In 2003 and 2004 we repurchased in open market and privately negotiated
transactions approximately $1,127.9 million of the outstanding principal amount
of 2006 Convertible Senior Notes, with proceeds of financings we consummated in
July 2003, through equity swaps and with the proceeds of our offerings of our
4.75% Contingent Convertible Senior Notes Due 2023 ("2023 Convertible Notes") in
November 2003. In addition, in February 2004, we initiated a cash tender offer
for all of the outstanding 2006 Convertible Senior Notes for a price of par plus
accrued interest. Approximately $409.4 million aggregate principal amount of the
2006 Convertible Senior Notes were tendered pursuant to the tender offer, for
which we paid a total of $412.8 million (including accrued interest of $3.4
million). At June 30, 2004, 2006 Convertible Senior Notes in the aggregate
principal amount of $72.1 million remain outstanding.
-55-
In addition, $276.0 million of our outstanding HIGH TIDES are scheduled to
be remarketed no later than November 1, 2004, $360.0 million of our HIGH TIDES
are scheduled to be remarketed no later than February 1, 2005 and $517.5 million
of our HIGH TIDES are scheduled to be remarketed no later than August 1, 2005.
In the event of a failed remarketing, the relevant HIGH TIDES will remain
outstanding as convertible securities at a term rate equal to the treasury rate
plus 6% per annum and with a term conversion price equal to 105% of the average
closing price of our common stock for the five consecutive trading days after
the applicable final failed remarketing termination date. While a failed
remarketing of our HIGH TIDES would not have a material effect on our liquidity
position, it would impact our calculation of diluted earnings per share and
increase our interest expense. Even with a successful remarketing, we would
expect to have an increased dilutive impact on our EPS based on a revised
conversion ratio. See Note 3 of the Notes to Consolidated Condensed Financial
Statements for a summary of HIGH TIDES repurchased by the Company through June
30, 2004.
We expect to have sufficient liquidity from cash flow from operations,
borrowings available under lines of credit, access to sale/leaseback and project
financing markets, sale or monetization of certain assets and cash balances to
satisfy all current obligations under our outstanding indebtedness, and to fund
anticipated capital expenditures and working capital requirements for the next
twelve months. On June 30, 2004, our liquidity totaled approximately $1.3
billion. This included cash and cash equivalents on hand of $0.8 billion,
current portion of restricted cash and cash escrowed for debt repurchases of
approximately $0.4 billion and approximately $0.1 billion of borrowing capacity
under our various credit facilities.
Cash Flow Activities -- The following table summarizes our cash flow
activities for the periods indicated:
Six Months Ended
June 30,
----------------------------
2004 2003
------------- -------------
(In thousands)
Beginning cash and cash equivalents.................................. $ 991,806 $ 579,486
Net cash provided by (used in):
Operating activities.............................................. 11,993 113,304
Investing activities.............................................. (167,391) (1,297,803)
Financing activities.............................................. 20,769 1,017,314
Effect of exchange rates changes on cash and cash equivalents..... (13,146) 5,653
------------ ------------
Net decrease in cash and cash equivalents......................... (147,775) (161,532)
------------ ------------
Ending cash and cash equivalents..................................... $ 844,031 $ 417,954
============ ============
Operating activities for the six months ended June 30, 2004, provided net
cash of $12.0 million, compared to $113.3 million for the same period in 2003.
Operating cash flows in 2004 benefited from the receipt of $100.6 million from
the restructuring and sale of power purchase agreements for two of our New
Jersey power plants and $16.4 million from the restructuring of a long-term gas
supply contract. In the first six months of 2004, there was a $49.9 million use
of funds from net changes in operating assets and liabilities, comprised of a
$39.9 million increase in net margin deposits posted to support CES contracting
activity, in addition to net increases in accounts receivable and accounts
payable and other working capital accounts.
In the first six months of 2003, operating cash flows benefited from our
equity method investment in the Acadia facility where distributions exceeded
income recognized by $53.9 million, while there was a $408.3 million use of
funds from net changes in operating assets and liabilities, which primarily was
a result of higher accounts receivable balances and higher net margin deposits
and prepaid gas balances to support our contracting activity in 2003.
Investing activities for the six months ended June 30, 2004, consumed net
cash of $167.4 million, as compared to $1,297.8 million in the same period of
2003. Capital expenditures for the completion of our power facilities decreased
in 2004, as there were fewer projects under construction. Investing activities
in 2004 reflect the receipt of $257.6 million from the sale our Lost Pines Power
Plant, a portion of the proceeds from the sale of a subsidiary holding power
purchase agreements for two of our New Jersey power plants, and from the sale of
certain oil and gas properties. These sales compare to $13.7 million of proceeds
from disposals in the prior year. We also reported a $180.8 million increase in
cash used for acquisitions in 2004 vs. 2003, as we used the proceeds from the
Lost Pines sale and cash on hand to purchase the Los Brazos Power Plant, the
remaining 50% interest in the Aries Power Plant, and the remaining 20% interest
in Calpine Cogeneration Company. Finally, the $452.4 million decrease in
restricted cash served as an investing activity inflow in 2004. The restricted
cash balance decreased in connection with the repurchase of debt with restricted
cash (primarily the Convertible Senior Notes Due 2006.)
-56-
Financing activities for the six months ended June 30, 2004, provided $20.8
million, compared to $1,017.3 million for the same period in 2003. We continued
our refinancing program in 2004, by raising $2.4 billion to repay $2.3 billion
of CCFC II project financing. In 2004, we also raised $250 million from the
issuance of Convertible Senior Notes Due 2023 pursuant to an option exercise and
$924.5 million from various project financings. During the period, we repaid
$596.9 million in project financing debt, and we used $586.9 million of proceeds
from convertible senior notes offerings to repurchase the majority of
outstanding Convertible Senior Notes Due 2006 that come due in December.
Counterparties and Customers -- Our customer and supplier base is
concentrated within the energy industry. Additionally, we have exposure to
trends within the energy industry, including declines in the creditworthiness of
our marketing counterparties. Currently, multiple companies within the energy
industry are in bankruptcy or have below investment grade credit ratings. While
our current credit exposure to CDWR is significant, CDWR has been paying its
obligations to us on a current basis.
Letter of Credit Facilities -- At June 30, 2004 and December 31, 2003, we
had approximately $435.6 million and $410.8 million, respectively, in letters of
credit outstanding under various credit facilities to support CES risk
management and other operational and construction activities. Of the total
letters of credit outstanding, $260.0 million and $272.1 million were in
aggregate issued under our cash collateralized letter of credit facility and the
corporate revolving credit facility at June 30, 2004 and December 31, 2003,
respectively.
In addition, in August 2004, our newly created entity Calpine Energy
Management entered into a $250.0 million letter of credit facility with Deutsche
Bank. See Note 16 of the Notes to Consolidated Condensed Financial Statements
for more information regarding this letter of credit facility.
CES Margin Deposits and Other Credit Support -- As of June 30, 2004 and
December 31, 2003, CES had deposited net amounts of $227.9 million and $188.0
million, respectively, in cash as margin deposits with third parties and had
letters of credit outstanding of $3.5 million and $14.5 million, respectively.
CES uses these margin deposits and letters of credit as credit support for the
gas procurement and risk management activities it conducts on Calpine's behalf.
Future cash collateral requirements may increase based on the extent of our
involvement in derivative activities and movements in commodity prices and also
based on our credit ratings and general perception of creditworthiness in this
market. While we believe that we have adequate liquidity to support CES's
operations at this time, it is difficult to predict future developments and the
amount of credit support that we may need to provide as part of our business
operations.
Capital Availability -- Access to capital for many in the energy sector,
including us, has been restricted since late 2001. While we have been able to
access the capital and bank credit markets in this new environment, it has been
on significantly different terms than in the past. In particular, our senior
working capital facility and term loan financings and the majority of our debt
securities offered and sold in this period, have been secured by certain of our
assets and equity interests. While we believe we will be successful in
refinancing all debt before maturity, the terms of financing available to us now
and in the future may not be attractive to us and the timing of the availability
of capital is uncertain and is dependent, in part, on market conditions that are
difficult to predict and are outside of our control. We do not have any
significant debt obligations due from July 2004 through December 31, 2005. See
Note 8 of the Notes to Consolidated Condensed Financial Statements for
additional information on debt obligations.
During the six months ended June 30, 2004:
Our wholly owned subsidiary Calpine Generating Company, LLC ("CalGen"),
formerly Calpine Construction Finance Company II, LLC ("CCFC II"), completed a
secured institutional term loan and secured note financing, totaling $2.4
billion before transaction costs and fees. Net proceeds from the financing were
used to refinance amounts outstanding under the $2.5 billion CCFC II revolving
construction credit facility, which was scheduled to mature in November 2004,
and to pay fees and transaction costs associated with the refinancing.
One of the initial purchasers of the 2023 Convertible Notes exercised in
full its option to purchase an additional $250.0 million of these notes.
We repurchased approximately $178.5 million in principal amount of the 2006
Convertible Senior Notes in exchange for approximately $177.5 million in cash.
Additionally, on February 9, 2004, we made a cash tender offer, which expired on
March 9, 2004, for any and all of the then still outstanding 2006 Convertible
Senior Notes at a price of par plus accrued interest. On March 10, 2004, we paid
an aggregate amount of $412.8 million for the tendered 2006 Convertible Senior
Notes, which included accrued interest of $3.4 million. At June 30, 2004, 2006
Convertible Senior Notes in the aggregate principal amount of $72.1 million
remained outstanding.
-57-
Rocky Mountain Energy Center, LLC and Riverside Energy Center, LLC, wholly
owned stand-alone subsidiaries of our subsidiary Calpine Riverside Holdings,
LLC, received funding in the aggregate amount of $661.5 million of floating rate
secured institutional term loans and a letter of credit-linked deposit. See Note
8 of the Notes to Consolidated Condensed Financial Statements for more
information.
Asset Sales -- As a result of the significant contraction in the
availability of capital for participants in the energy sector, we have adopted a
strategy of conserving our core strategic assets and disposing of certain less
strategically important assets, which serves partially to strengthen our balance
sheet through repayment of debt.
Effective Tax Rate -- Our effective tax rate is significantly impacted by
permanent items related to cross-border financings that are deductible for tax
purposes but not for book income purposes. The potential sale of our Canadian
oil and gas reserves (see Note 16 of the Notes to Consolidated Condensed
Financial Statements for more information on this potential sale) could cause a
significant decrease in certain of these permanent items and a corresponding
increase in our effective tax rate from our estimated tax rate for 2004 as of
June 30, 2004. However, because of significant net operating loss carryforwards
at June 30, 2004, we don't expect a change in effective tax rate to have a
material impact on cash taxes paid for 2004 or 2005.
We believe that our completion of the financing and asset sales liquidity
transactions described above in difficult conditions affecting the market, and
our sector in general, demonstrate our probable ability to have access to the
capital markets on acceptable terms in the future, although availability of
capital has tightened significantly throughout the power generation industry
and, therefore, there can be no assurance that we will have access to capital in
the future as and when we may desire or on terms that are attractive to us. We
expect to incur capital expenditures in the third and fourth quarters of 2004 of
approximately $150 million, net of expected project financings.
Off-Balance Sheet Commitments -- In accordance with Accounting Principles
Board ("APB") Opinion No. 18, "The Equity Method of Accounting For Investments
in Common Stock" and FASB Interpretation No. 35, "Criteria for Applying the
Equity Method of Accounting for Investments in Common Stock (An Interpretation
of APB Opinion No. 18)," the debt on the books of our unconsolidated investments
in power projects is not reflected on our Consolidated Condensed Balance Sheet.
At June 30, 2004, third-party investee debt was approximately $178.7 million.
Based on our pro rata ownership share of each of the investments, our share
would be approximately $58.3 million. However, all such debt is non-recourse to
us. See Note 5 of the Notes to Consolidated Condensed Financial Statements for
additional information on our equity method investments in power projects and
oil and gas properties.
We own a 32.3% interest in the unconsolidated equity method investee
Androscoggin Energy LLC ("AELLC"). AELLC owns the 160-MW Androscoggin Energy
Center located in Maine and has construction debt of $59.3 million outstanding
as of June 30, 2004. The debt is non-recourse to us (the "AELLC Non-Recourse
Financing"). On June 30, 2004, and December 31, 2003, our investment balance was
$14.5 million and $11.8 million, respectively, and our notes receivable balance
due from AELLC was $17.6 million and $13.3 million, respectively. On and after
August 8, 2003, AELLC received letters from its lenders claiming that certain
events of default hade occurred under the credit agreement for the AELLC
Non-Recourse Financing, including, among other things, that the project had been
and remained in default under its credit agreement because the lending
syndication had declined to extend the date for the conversion of the
construction loan to a term loan. AELLC disputes the purported defaults. Also,
the steam host for the AELLC project, International Paper Company ("IP"), filed
a complaint against AELLC in October 2000, which is discussed in more detail in
Note 13 of the Notes to Consolidated Condensed Financial Statements. IP's
complaint has been a complicating factor in converting the construction debt to
long term financing. As a result of these events, we reviewed our investment and
notes receivable balances and believe that the assets are not impaired. We
further believe that AELLC will eventually be able to convert the construction
loan to a term loan.
-58-
Capital Spending -- Development and Construction
Construction and development costs in process consisted of the following at
June 30, 2004 (dollars in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP (1) CIP Costs Equipment
-------- ------------- ------------- ------------- ---------
Projects in active construction..................... 9 $ 2,929,153 $ 980,425 $ -- $ --
Projects in advanced development.................... 13 720,982 585,866 129,158 --
Projects in suspended development................... 6 463,320 203,437 12,993 --
Projects in early development....................... 3 -- -- 8,933 14,001
Other capital projects.............................. NA 43,531 -- -- --
Unassigned equipment................................ NA -- -- -- 52,856
------------- ------------- ------------- ---------
Total construction and development costs......... $ 4,156,986 $ 1,769,728 $ 151,084 $ 66,857
============= ============= ============= =========
- ------------
<FN>
(1) Construction in Progress ("CIP").
</FN>
Projects in Active Construction -- The 9 projects in active construction
are estimated to come on line from September 2004 to June 2007. These projects
will bring on line approximately 4,266 MW of base load capacity (4,825 MW with
peaking capacity). Interest and other costs related to the construction
activities necessary to bring these projects to their intended use are being
capitalized. Five additional projects totaling 3,110 megawatts that were in
active construction in the beginning of the quarter went on line during the
quarter. At June 30, 2004, the estimated funding requirements to complete these
9 projects, net of expected project financing proceeds, is approximately $1.2
billion.
Projects in Advanced Development -- There are 13 projects in advanced
development. These projects will bring on line approximately 5,945 MW of base
load capacity (7,096 MW with peaking capacity). Interest and other costs related
to the development activities necessary to bring these projects to their
intended use are being capitalized. However, the capitalization of interest has
been suspended on two projects for which development activities are complete but
construction will not commence until a power purchase agreement and financing
are obtained. At June 30, 2004, the estimated cost to complete the 13 projects
in advanced development is approximately $3.9 billion. Our current plan is to
project finance these costs as power purchase agreements are arranged.
Suspended Development Projects -- Due to current electric market
conditions, we have ceased capitalization of additional development costs and
interest expense on certain development projects on which work has been
suspended. Capitalization of costs may recommence as work on these projects
resumes, if certain milestones and criteria are met. These projects would bring
on line approximately 3,169 MW of base load capacity (3,629 MW with peaking
capacity). At June 30, 2004, the estimated cost to complete the six projects is
approximately $1.9 billion.
Projects in Early Development -- Costs for projects that are in early
stages of development are capitalized only when it is highly probable that such
costs are ultimately recoverable and significant project milestones are
achieved. Until then all costs, including interest costs, are expensed. The
projects in early development with capitalized costs relate to three projects
and include geothermal drilling costs and equipment purchases.
Other Capital Projects -- Other capital projects primarily consist of
enhancements to operating power plants, oil and gas and geothermal resource and
facilities development as well as software developed for internal use.
Unassigned Equipment -- As of June 30, 2004, we had made progress payments
on 4 turbines, 1 heat recovery steam generator, and other equipment with an
aggregate carrying value of $66.9 million representing unassigned equipment that
is classified on the balance sheet as other assets because it is not assigned to
specific development and construction projects. We are holding this equipment
for potential use on future projects. It is possible that some of this
unassigned equipment may eventually be sold, potentially in combination with our
engineering and construction services. For equipment that is not assigned to
development or construction projects, interest is not capitalized.
Impairment Evaluation -- All construction and development projects and
unassigned turbines are reviewed for impairment whenever there is an indication
of potential reduction in fair value. Equipment assigned to such projects is not
evaluated for impairment separately, as it is integral to the assumed future
operations of the project to which it is assigned. If it is determined that it
is no longer probable that the projects will be completed and all capitalized
costs recovered through future operations, the carrying values of the projects
-59-
would be written down to the recoverable value in accordance with the provisions
of SFAS No. 144. We review our unassigned equipment for potential impairment
based on probability-weighted alternatives of utilizing the equipment for future
projects versus selling the equipment. Utilizing this methodology, we do not
believe that the equipment not committed to sale is impaired.
Performance Metrics
In understanding our business, we believe that certain non-GAAP operating
performance metrics are particularly important. These are described below:
Total deliveries of power. We both generate power that we sell to third
parties and purchase power for sale to third parties in hedging, balancing and
optimization ("HBO") transactions. The former sales are recorded as electricity
and steam revenue and the latter sales are recorded as sales of purchased power
for hedging and optimization. The volumes in MWh for each are key indicators of
our respective levels of generation and HBO activity and the sum of the two, our
total deliveries of power, is relevant because there are occasions where we can
either generate or purchase power to fulfill contractual sales commitments.
Prospectively beginning October 1, 2003, in accordance with EITF 03-11, certain
sales of purchased power for hedging and optimization are shown net of purchased
power expense for hedging and optimization in our consolidated statement of
operations. Accordingly, we have also netted HBO volumes on the same basis as of
October 1, 2003, in the table below.
Average availability and average baseload capacity factor or operating
rate. Availability represents the percent of total hours during the period that
our plants were available to run after taking into account the downtime
associated with both scheduled and unscheduled outages. The baseload capacity
factor, sometimes called operating rate, is calculated by dividing (a) total
megawatt hours generated by our power plants (excluding peakers) by the product
of multiplying (b) the weighted average megawatts in operation during the period
by (c) the total hours in the period. The capacity factor is thus a measure of
total actual generation as a percent of total potential generation. If we elect
not to generate during periods when electricity pricing is too low or gas prices
too high to operate profitably, the baseload capacity factor will reflect that
decision as well as both scheduled and unscheduled outages due to maintenance
and repair requirements.
Average heat rate for gas-fired fleet of power plants expressed in British
Thermal Units ("Btu") of fuel consumed per KWh generated. We calculate the
average heat rate for our gas-fired power plants (excluding peakers) by dividing
(a) fuel consumed in Btu's by (b) KWh generated. The resultant heat rate is a
measure of fuel efficiency, so the lower the heat rate, the better. We also
calculate a "steam-adjusted" heat rate, in which we adjust the fuel consumption
in Btu's down by the equivalent heat content in steam or other thermal energy
exported to a third party, such as to steam hosts for our cogeneration
facilities. Our goal is to have the lowest average heat rate in the industry.
Average all-in realized electric price expressed in dollars per MWh
generated. Our risk management and optimization activities are integral to our
power generation business and directly impact our total realized revenues from
generation. Accordingly, we calculate the all-in realized electric price per MWh
generated by dividing (a) adjusted electricity and steam revenue, which includes
capacity revenues, energy revenues, thermal revenues and the spread on sales of
purchased power for hedging, balancing, and optimization activity, by (b) total
generated MWh in the period.
Average cost of natural gas expressed in dollars per millions of Btu's of
fuel consumed. Our risk management and optimization activities related to fuel
procurement directly impact our total fuel expense. The fuel costs for our
gas-fired power plants are a function of the price we pay for fuel purchased and
the results of the fuel hedging, balancing, and optimization activities by CES.
Accordingly, we calculate the cost of natural gas per millions of Btu's of fuel
consumed in our power plants by dividing (a) adjusted fuel expense which
includes the cost of fuel consumed by our plants (adding back cost of
inter-company "equity" gas from Calpine Natural Gas, which is eliminated in
consolidation), and the spread on sales of purchased gas for hedging, balancing,
and optimization activity by (b) the heat content in millions of Btu's of the
fuel we consumed in our power plants for the period.
Average spark spread expressed in dollars per MWh generated. Our risk
management activities focus on managing the spark spread for our portfolio of
power plants, the spread between the sales price for electricity generated and
the cost of fuel. We calculate the spark spread per MWh generated by subtracting
(a) adjusted fuel expense from (b) adjusted E&S revenue and dividing the
difference by (c) total generated MWh in the period.
Average plant operating expense per normalized MWh. To assess trends in
electric power plant operating expense ("POX") per MWh, we normalize the results
from period to period by assuming a constant 70% total company-wide capacity
factor (including both base load and peaker capacity) in deriving normalized
MWh. By normalizing the cost per MWh with a constant capacity factor, we can
better analyze trends and the results of our program to realize economies of
scale, cost reductions and efficiencies at our electric generating plants.
-60-
The table below presents, the operating performance metrics discussed
above.
Three Months Ended June 30, Six Months Ended June 30,
---------------------------- ----------------------------
2004 2003 2004 2003
------------- ------------- ------------- -------------
(In thousands)
Operating Performance Metrics:
Total deliveries of power:
MWh generated...................................... 22,083 17,519 43,132 36,622
HBO and trading MWh sold........................... 20,883 20,647 40,481 38,168
------------- ------------- ------------- -------------
MWh delivered...................................... 42,966 38,166 83,613 74,790
============= ============= ============= =============
Average availability.................................. 89% 87% 90% 88%
Average baseload capacity factor:
Average total MW in operation...................... 24,357 19,218 23,134 18,666
Less: Average MW of pure peakers................... 2,951 2,684 2,951 2,451
------------- ------------- ------------- -------------
Average baseload MW in operation................... 21,406 16,534 20,183 16,215
Hours in the period................................ 2,184 2,184 4,368 4,344
Potential baseload generation (MWh)................ 46,751 36,110 88,159 70,438
Actual total generation (MWh)...................... 22,083 17,519 43,132 36,622
Less: Actual pure peakers' generation (MWh)........ 300 140 573 311
------------- ------------- ------------- -------------
Actual baseload generation (MWh)................... 21,783 17,379 42,559 36,311
Average baseload capacity factor................... 47% 48% 48% 52%
Average heat rate for gas-fired power plants
(excluding peakers) (Btu's/KWh):
Not steam adjusted................................. 8,272 8,019 8,221 7,992
Steam adjusted..................................... 7,203 7,234 7,160 7,231
Average all-in realized electric price:
Electricity and steam revenue...................... $ 1,312,792 $ 1,046,260 $ 2,558,678 $ 2,146,328
Spread on sales of purchased power for
hedging and optimization.......................... 51,483 6,086 56,572 7,421
------------- ------------- ------------- -------------
Adjusted electricity and steam revenue (in
thousands)........................................ $ 1,364,275 $ 1,052,346 $ 2,615,250 $ 2,153,749
MWh generated (in thousands)....................... 22,083 17,519 43,132 36,622
Average all-in realized electric price per MWh..... $ 61.78 $ 60.07 $ 60.63 $ 58.81
Average cost of natural gas:
Cost of oil and natural gas burned by power
plants (in thousands)............................. $ 839,736 $ 542,053 $ 1,610,190 $ 1,166,902
Fuel cost elimination.............................. 87,227 96,461 167,337 206,795
------------- ------------- ------------- -------------
Adjusted fuel expense.............................. $ 926,963 $ 638,514 $ 1,777,527 $ 1,373,697
Million Btu's ("MMBtu") of fuel consumed by
generating plants (in thousands).................. 162,078 122,422 312,435 245,358
Average cost of natural gas per MMBtu.............. $ 5.72 $ 5.22 $ 5.69 $ 5.60
MWh generated (in thousands)....................... 22,083 17,519 43,132 36,622
Average cost of adjusted fuel expense per MWh...... $ 41.98 $ 36.45 $ 41.21 $ 37.51
Average spark spread:
Adjusted electricity and steam revenue (in
thousands)........................................ $ 1,364,275 $ 1,052,346 $ 2,615,250 $ 2,153,749
Less: Adjusted fuel expense (in thousands)......... 926,963 638,514 1,777,527 1,373,697
------------- ------------- ------------- -------------
Spark spread (in thousands)........................ $ 437,312 $ 413,832 $ 837,723 $ 780,052
MWh generated (in thousands)....................... 22,083 17,519 43,132 36,622
Average spark spread per MWh....................... $ 19.80 $ 23.62 $ 19.42 $ 21.30
Add: Equity gas contribution(1).................... $ 46,547 $ 57,984 $ 89,233 $ 129,260
Spark spread with equity gas benefits (in
thousands)........................................ $ 483,859 $ 471,816 $ 926,956 $ 909,312
Average spark spread with equity gas benefits
per MWh........................................... $ 21.91 $ 26.93 $ 21.49 $ 24.83
Average plant operating expense ("POX") per
normalized MWh (We also show POX per actual MWh
for comparison):
Average total consolidated MW in operations........ 24,357 19,218 23,134 18,666
Hours in the period................................ 2,184 2,184 4,368 4,344
Total potential MWh................................ 53,196 41,972 101,049 81,085
Normalized MWh (at 70% capacity factor)............ 37,237 29,380 70,735 56,760
Plant operating expense (POX)...................... $ 223,664 $ 159,647 $ 399,498 $ 321,574
POX per normalized MWh............................. $ 6.01 $ 5.43 $ 5.65 $ 5.67
POX per actual MWh................................. $ 10.13 $ 9.11 $ 9.26 $ 8.78
- ------------
<FN>
(1) Equity gas contribution margin:
</FN>
-61-
Three Months Ended June 30, Six Months Ended June 30,
---------------------------- ----------------------------
2004 2003 2004 2003
------------- ------------- ------------- -------------
(In thousands)
Oil and gas sales................................... $ 26,069 $ 29,299 $ 50,651 $ 55,210
Add: Fuel cost eliminated in consolidation.......... 87,227 96,461 167,337 206,795
------------- ------------- ------------- -------------
Subtotal......................................... $ 113,296 $ 125,760 $ 217,988 $ 262,005
Less: Oil and gas operating expense................. 23,443 29,033 45,770 54,694
Less: Depletion, depreciation and amortization...... 43,307 38,743 82,985 78,051
------------- ------------- ------------- -------------
Equity gas contribution margin...................... $ 46,546 57,984 $ 89,233 129,260
MWh generated (in thousands)........................ 22,083 17,519 43,132 36,622
Equity gas contribution margin per MWh.............. $ 2.11 $ 3.31 $ 2.07 $ 3.53
The table below provides additional detail of total mark-to-market
activity. For the three and six months ended June 30, 2004 and 2003,
mark-to-market activity, net consisted of (dollars in thousands):
Three Months Ended June 30, Six Months Ended June 30,
---------------------------- ----------------------------
2004 2003 2004 2003
------------- ------------- ------------- -------------
Mark-to-market activity, net
Realized:
Power activity
"Trading Activity" as defined in EITF No. 02-03.... $ 11,138 $ 9,826 $ 29,847 $ 24,662
Ineffectiveness related to cash flow hedges........ -- -- -- --
Other mark-to-market activity(1)................... (4,773) -- (5,944) --
------------- ------------- ------------- -------------
Total realized power activity.................... $ 6,365 $ 9,826 $ 23,903 $ 24,662
============= ============= ============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03.... $ (57) $ (766) $ (131) $ 5,612
Ineffectiveness related to cash flow hedges........ -- -- -- --
Other mark-to-market activity(1)................... -- -- -- --
------------- ------------- ------------- -------------
Total realized gas activity...................... $ (57) $ (766) $ (131) $ 5,612
============= ============= ============= =============
Total realized activity:
"Trading Activity" as defined in EITF No. 02-03.... $ 11,081 $ 9,060 $ 29,716 $ 30,274
Ineffectiveness related to cash flow hedges........ -- -- -- --
Other mark-to-market activity(1)................... (4,773) -- (5,944) --
------------- ------------- ------------- -------------
Total realized activity.......................... $ 6,308 $ 9,060 $ 23,772 $ 30,274
============= ============= ============= =============
Unrealized:
Power activity
"Trading Activity" as defined in EITF No. 02-03.... $ (23,178) $ (11,232) $ (23,869) $ (13,113)
Ineffectiveness related to cash flow hedges........ 666 (1,612) 126 (4,638)
Other mark-to-market activity(1)................... (2,981) -- (12,776) --
------------- ------------- ------------- -------------
Total unrealized power activity.................. $ (25,493) $ (12,844) $ (36,519) $ (17,751)
============= ============= ============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03.... $ (3,737) $ 3,556 $ (3,102) $ 1,579
Ineffectiveness related to cash flow hedges........ 317 2,067 5,763 8,180
Other mark-to-market activity(1)................... -- -- -- --
------------- ------------- ------------- -------------
Total unrealized gas activity.................... $ (3,420) $ 5,623 $ 2,661 $ 9,759
============= ============= ============= =============
Total unrealized activity:
"Trading Activity" as defined in EITF No. 02-03....... $ (26,915) $ (7,676) $ (26,971) $ (11,534)
Ineffectiveness related to cash flow hedges........... 983 455 5,889 3,542
Other mark-to-market activity(1)...................... (2,981) -- (12,776) --
------------- ------------- ------------- -------------
Total unrealized activity........................ $ (28,913) $ (7,221)$ (33,858) $ (7,992)
============= ============= ============= =============
Total mark-to-market activity:
"Trading Activity" as defined in EITF No. 02-03....... $ (15,834) $ 1,384 $ 2,745 $ 18,740
Ineffectiveness related to cash flow hedges........... 983 455 5,889 3,542
Other mark-to-market activity(1)...................... (7,754) -- (18,720) --
------------- ------------- ------------- -------------
Total mark-to-market activity.................... $ (22,605) $ 1,839 $ (10,086) $ 22,282
============= ============= ============= =============
- ------------
<FN>
(1) Activity related to our assets but does not qualify for hedge accounting.
</FN>
-62-
Overview
Summary of Key Activities
Finance - New Issuances
Date Amount Description
- --------- -------------- -----------------------------------------------------
6/2/04 $85.0 million PCF III issued $85.0 million in zero coupon notes
6/29/04 $661.5 million Rocky Mountain Energy Center, LLC, and Riverside
Energy Center, LLC, closed an offering of First
Priority Secured Floating Rate Term Loans Due 2011
and a letter of credit-linked deposit facility
Finance - Repurchases/Retirements
Date Amount Description
- --------- -------------- -----------------------------------------------------
5/04 $78.8 million Retirement of Newark and Parlin Power Plants project
financing
4/04-6/04 $46.6 million Repurchased $46.6 million in principal amount of
outstanding senior notes for $41.5 million in cash
4/04-6/04 $95.0 million Exchanged 20.1 million Calpine common shares in
privately negotiated transactions for approximately
$20.0 million par value of HIGH TIDES I and
approximately $75.0 million par value of HIGH TIDES
II
Other:
Date Description
- --------- --------------------------------------------------------------------
4/26/04 Successfully completed consent solicitation to effect certain
amendments to the Indentures governing the Senior Notes issued
between 1996 and 1999
5/19/04 Restructured King City lease
5/25/04 Signed a 25-year agreement to sell up to 200 megawatts of electricity
and 1 million pounds per hour of steam to The Dow Chemical Company
5/26/04 JCPL terminated its existing tolling arrangements with the Newark and
Parlin Power Plants resulting in a gain of $100.6 million before
transaction costs
5/26/04 Sold Utility Contract Funding II, a wholly owned subsidiary of CES,
which had sold a long-term power purchase agreement related to
Newark and Parlin Power Plants, for a pre-tax gain of $85.4 million
before transaction costs
6/9/04 Received approval from the CPUC for a tolling agreement with San
Diego Gas and Electric that provides for the delivery of up to 600
megawatts of capacity for ten years beginning in 2008
6/11/04 Citrus Trading Corp. negotiated early partial termination of its gas
contract with the Auburndale facility for a net gain of $11.7
million
Power Plant Development and Construction:
Date Project Description
- --------- ---------------------------------- --------------------
5/04 Osprey Energy Center Commercial operation
5/04 Columbia Energy Center Commercial operation
5/04 Rocky Mountain Energy Center Commercial operation
5/04 Valladolid III IP Construction began
6/04 Riverside Energy Center Commercial operation
6/04 Deer Park Energy Center Expansion Commercial operation
6/04 Freeport Energy Center Construction began
California Power Market
California Refund Proceeding. On August 2, 2000, the California Refund
Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric
Company under Section 206 of the Federal Power Act alleging, among other things,
that the markets operated by the California Independent System Operator
("CAISO") and the California Power Exchange ("CalPX") were dysfunctional. In
addition to commencing an inquiry regarding the market structure, FERC
established a refund effective period of October 2, 2000, to June 19, 2001, for
sales made into those markets.
On December 12, 2002, the Administrative Law Judge ("ALJ") issued a
Certification of Proposed Finding on California Refund Liability ("December 12
Certification") making an initial determination of refund liability. On March
26, 2003, FERC also issued an order adopting many of the ALJ's findings set
forth in the December 12 Certification (the "March 26 Order"). In addition, as a
result of certain findings by the FERC staff concerning the unreliability or
misreporting of certain reported indices for gas prices in California during the
refund period, FERC ordered that the basis for calculating a party's potential
refund liability be modified by substituting a gas proxy price based upon gas
-63-
prices in the producing areas plus the tariff transportation rate for the
California gas price indices previously adopted in the refund proceeding. We
believe, based on the available information, that any refund liability that may
be attributable to us will increase modestly, from approximately $6.2 million to
$8.4 million, after taking the appropriate set-offs for outstanding receivables
owed by the CalPX and CAISO to us. We have fully reserved the amount of refund
liability that by our analysis would potentially be owed under the refund
calculation clarification in the March 26 order. The final determination of the
refund liability is subject to further Commission proceedings to ascertain the
allocation of payment obligations among the numerous buyers and sellers in the
California markets. At this time, we are unable to predict the timing of the
completion of these proceedings or the final refund liability. Thus the impact
on our business is uncertain at this time.
On April 26, 2004, Dynegy Inc. entered into a settlement of the California
Refund Proceeding and other proceedings with California governmental entities
and the three California investor-owned utilities. The California governmental
entities include the Attorney General, the California Public Utilities
Commission ("CPUC"), the California Department of Water Resources ("CDWR"), and
the California Electricity Oversight Board. Also, on April 27, 2004, The
Williams Companies, Inc. ("Williams") entered into a settlement of the
California Refund Proceeding and other proceedings with the three California
investor-owned utilities; previously, Williams had entered into a settlement of
the same matters with the California governmental entities. The Williams
settlement with the California governmental entities was similar to the
settlement that we entered into with the California governmental entities on
April 22, 2002. Our settlement was approved by FERC on March 26, 2004, in an
order which partially dismissed us from the California Refund Proceeding to the
extent that any refunds are owed for power sold by us to CDWR or any other
agency of the State of California. On June 30, 2004, a settlement conference was
convened at the FERC to explore settlements among additional parties.
FERC Investigation into Western Markets. On February 13, 2002, FERC
initiated an investigation of potential manipulation of electric and natural gas
prices in the western United States. This investigation was initiated as a
result of allegations that Enron and others used their market position to
distort electric and natural gas markets in the West. The scope of the
investigation is to consider whether, as a result of any manipulation in the
short-term markets for electric energy or natural gas or other undue influence
on the wholesale markets by any party since January 1, 2000, the rates of the
long-term contracts subsequently entered into in the West are potentially unjust
and unreasonable. FERC has stated that it may use the information gathered in
connection with the investigation to determine how to proceed on any existing or
future complaint brought under Section 206 of the Federal Power Act involving
long-term power contracts entered into in the West since January 1, 2000, or to
initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding
on its own initiative. On August 13, 2002, the FERC staff issued the Initial
Report on Company-Specific Separate Proceedings and Generic Reevaluations;
Published Natural Gas Price Data; and Enron Trading Strategies (the "Initial
Report") summarizing its initial findings in this investigation. There were no
findings or allegations of wrongdoing by us set forth or described in the
Initial Report. On March 26, 2003, the FERC staff issued a final report in this
investigation (the "Final Report"). The FERC staff recommended that FERC issue a
show cause order to a number of companies, including us, regarding certain power
scheduling practices that may have been be in violation of the CAISO's or
CalPX's tariff. The Final Report also recommended that FERC modify the basis for
determining potential liability in the California Refund Proceeding discussed
above. We believe that we did not violate these tariffs and that, to the extent
that such a finding could be made, any potential liability would not be
material.
Also, on June 25, 2003, FERC issued a number of orders associated with
these investigations, including the issuance of two show cause orders to certain
industry participants. FERC did not subject us to either of the show cause
orders. FERC also issued an order directing the FERC Office of Markets and
Investigations to investigate further whether market participants who bid a
price in excess of $250 per megawatt hour into markets operated by either the
CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may
have violated CAISO and CalPX tariff prohibitions. No individual market
participant was identified. We believe that we did not violate the CAISO and
CalPX tariff prohibitions referred to by FERC in this order; however, we are
unable to predict at this time the final outcome of this proceeding or its
impact on us.
CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our
Qualifying Facilities ("QF") contracts with PG&E provide that the CPUC has the
authority to determine the appropriate utility "avoided cost" to be used to set
energy payments for certain QF contracts by determining the short run avoided
cost ("SRAC") energy price formula. In mid-2000 our QF facilities elected the
option set forth in Section 390 of the California Public Utility Code, which
provides QFs the right to elect to receive energy payments based on the CalPX
market clearing price instead of the price determined by SRAC. Having elected
such option, we were paid based upon the PX zonal day-ahead clearing price ("PX
Price") from summer 2000 until January 19, 2001, when the PX ceased operating a
day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine
-64-
whether the PX Price was the appropriate price for the energy component upon
which to base payments to QFs which had elected the PX-based pricing option. The
CPUC at one point issued a proposed decision to the effect that the PX Price was
the appropriate price for energy payments under the California Public Utility
Code but tabled it, and a final decision has not been issued to date. Therefore,
it is possible that the CPUC could order a payment adjustment based on a
different energy price determination. On April 29, 2004, PG&E, The Utility
Reform Network, which is a consumer advocacy group, and the Office of Ratepayer
Advocates, which is an independent consumer advocacy department of the CPUC,
(collectively, the "PG&E Parties") filed a Motion for Briefing Schedule
Regarding True-Up of Payments to QF Switchers (the "April 29 Motion"). The April
29 Motion requests that the CPUC set a briefing schedule under the R.99-11-022
to determine refund liability of the QFs who had switched to the PX Price during
the period of June 1, 2000, until January 19, 2001. The PG&E Parties allege that
refund liability be determined using the methodology that has been developed
thus far in the California Refund Proceeding discussed above. We believe that
the PX Price was the appropriate price for energy payments and that the basis
for any refund liability based on the interim determination by FERC in the
California Refund Proceeding is unfounded, but there can be no assurance that
this will be the outcome of the CPUC proceedings.
Geysers Reliability Must Run Section 206 Proceeding. CAISO, California
Electricity Oversight Board, Public Utilities Commission of the State of
California, Pacific Gas and Electric Company, San Diego Gas & Electric Company,
and Southern California Edison (collectively referred to as the "Buyers
Coalition") filed a complaint on November 2, 2001 at the FERC requesting the
commencement of a Federal Power Act Section 206 proceeding to challenge one
component of a number of separate settlements previously reached on the terms
and conditions of "reliability must run" contracts ("RMR Contracts") with
certain generation owners, including Geysers Power Company, LLC, which
settlements were also previously approved by the FERC. RMR Contracts require the
owner of the specific generation unit to provide energy and ancillary services
when called upon to do so by the ISO to meet local transmission reliability
needs or to manage transmission constraints. The Buyers Coalition has asked FERC
to find that the availability payments under these RMR Contracts are not just
and reasonable. Geysers Power Company, LLC filed an answer to the complaint in
November 2001. To date, FERC has not established a Section 206 proceeding. The
outcome of this litigation and the impact on our business cannot be determined
at the present time.
Financial Market Risks
As we are primarily focused on generation of electricity using gas-fired
turbines, our natural physical commodity position is "short" fuel (i.e., natural
gas consumer) and "long" power (i.e., electricity seller). To manage forward
exposure to price fluctuation in these and (to a lesser extent) other
commodities, we enter into derivative commodity instruments.
The change in fair value of outstanding commodity derivative instruments
from January 1, 2004 through June 30, 2004, is summarized in the table below (in
thousands):
Fair value of contracts outstanding at January 1, 2004............. $ 76,541
Gains recognized or otherwise settled during the period(1)......... (15,781)
Changes in fair value attributable to new contracts................ (8,943)
Changes in fair value attributable to price movements.............. (42,359)
-----------
Fair value of contracts outstanding at June 30, 2004(2)......... $ 9,458
===========
- ------------
(1) Recognized losses from commodity cash flow hedges of $(8.0) million
(represents realized value of cash flow hedge activity of $(17.8) million
as disclosed in Note 10 of the Notes to Consolidated Condensed Financial
Statements, net of terminated derivatives of $(14.7) million and equity
method hedges of $4.9 million) and $23.8 million realized gain on
mark-to-market activity, which is reported in the Consolidated Condensed
Statements of Operations under mark-to-market activities, net. (2) Net
commodity derivative assets reported in Note 10 of the Notes to
Consolidated Condensed Financial Statements.
The fair value of outstanding derivative commodity instruments at June 30
based on price source and the period during which the instruments will mature,
are summarized in the table below (in thousands):
Fair Value Source 2004 2005-2006 2007-2008 After 2008 Total
- ----------------------------------------------------- ----------- ----------- ----------- ---------- ----------
Prices actively quoted............................... $ 50,589 $ 124,089 $ -- $ -- $ 174,678
Prices provided by other external sources............ (103,584) (35,028) 7,421 (20,799) (151,990)
Prices based on models and other valuation methods... -- 3,782 1,063 (18,075) (13,230)
---------- ---------- ---------- --------- ----------
Total fair value.................................. $ (52,995) $ 92,843 $ 8,484 $ (38,874) $ 9,458
========== ========== ========== ========= ==========
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Our risk managers maintain fair value price information derived from
various sources in our risk management systems. The propriety of that
information is validated by our Risk Control group. Prices actively quoted
include validation with prices sourced from commodities exchanges (e.g., New
York Mercantile Exchange). Prices provided by other external sources include
quotes from commodity brokers and electronic trading platforms. Prices based on
models and other valuation methods are validated using quantitative methods.
The counterparty credit quality associated with the fair value of
outstanding derivative commodity instruments at June 30 and the period during
which the instruments will mature are summarized in the table below (in
thousands):
Credit Quality 2004 2005-2006 2007-2008 After 2008 Total
- ----------------------------------------------------- ----------- ----------- ----------- ---------- ----------
(Based on Standard & Poor's Ratings as of July 7, 2004)
Investment grade..................................... $ (60,497) $ 73,585 $ 8,831 $ (38,874) $ (16,955)
Non-investment grade................................. 10,930 20,093 -- -- 31,023
No external ratings.................................. (3,428) (835) (347) -- (4,610)
---------- ---------- ---------- ---------- ----------
Total fair value.................................. $ (52,995) $ 92,843 $ 8,484 $ (38,874) $ 9,458
========== ========== ========== ========== ==========
The fair value of outstanding derivative commodity instruments and the fair
value that would be expected after a 10% adverse price change are shown in the
table below (in thousands):
Fair Value
After 10%
Adverse
Fair Value Price Change
------------ ------------
At June 30, 2004:
Electricity............................. $ (150,394) $ (316,003)
Natural gas............................. 159,852 70,495
----------- -----------
Total................................ $ 9,458 $ (245,508)
=========== ===========
Derivative commodity instruments included in the table are those included
in Note 10 of the Notes to Consolidated Condensed Financial Statements. The fair
value of derivative commodity instruments included in the table is based on
present value adjusted quoted market prices of comparable contracts. The fair
value of electricity derivative commodity instruments after a 10% adverse price
change includes the effect of increased power prices versus our derivative
forward commitments. Conversely, the fair value of the natural gas derivatives
after a 10% adverse price change reflects a general decline in gas prices versus
our derivative forward commitments. Derivative commodity instruments offset the
price risk exposure of our physical assets. None of the offsetting physical
positions are included in the table above.
Price changes were calculated by assuming an across-the-board ten percent
adverse price change regardless of term or historical relationship between the
contract price of an instrument and the underlying commodity price. In the event
of an actual ten percent change in prices, the fair value of our derivative
portfolio would typically change by more than ten percent for earlier forward
months and less than ten percent for later forward months because of the higher
volatilities in the near term and the effects of discounting expected future
cash flows.
The primary factors affecting the fair value of our derivatives at any
point in time are (1) the volume of open derivative positions (MMBtu and MWh),
and (2) changing commodity market prices, principally for electricity and
natural gas. The total volume of open gas derivative positions increased 154%
from December 31, 2003, to June 30, 2004, while the total volume of open power
derivative positions increased 41% for the same period. In that prices for
electricity and natural gas are among the most volatile of all commodity prices,
there may be material changes in the fair value of our derivatives over time,
driven both by price volatility and the changes in volume of open derivative
transactions. Under SFAS No. 133, the change since the last balance sheet date
in the total value of the derivatives (both assets and liabilities) is reflected
either in Other Comprehensive Income ("OCI"), net of tax, or in the statement of
operations as an item (gain or loss) of current earnings. As of June 30, 2004, a
significant component of the balance in accumulated OCI represented the
unrealized net loss associated with commodity cash flow hedging transactions. As
noted above, there is a substantial amount of volatility inherent in accounting
for the fair value of these derivatives, and our results during the three and
six months ended June 30, 2004, have reflected this. See Note 11 of the Notes to
Consolidated Condensed Financial Statements for additional information on
derivative activity and OCI.
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Available-for-Sale Debt Securities -- We have exchanged 26.6 million
Calpine common shares in privately negotiated transactions for approximately
$132.5 million par value of HIGH TIDES I and HIGH TIDES II. As of June 30, 2004,
the repurchased HIGH TIDES are classified as available-for-sale and recorded at
fair market value in Other Assets. The following tables present our different
classes of debt securities held by expected maturity date and fair market value
as of June 30, 2004, (dollars in thousands):
Weighted
Average
Interest
Rate 2004 2005 2006 2007 2008 Thereafter Total
-------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
HIGH TIDES I........... 5.75% $ -- $ -- $ -- $ -- $ -- $ 57,500 $ 57,500
HIGH TIDES II.......... 5.50% -- -- -- -- -- 75,000 75,000
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total............... $ -- $ -- $ -- $ -- $ -- $ 132,500 $ 132,500
========== ========== ========== ========== ========== ========== ==========
Fair
Market
Value
----------
HIGH TIDES I............................ $ 55,919
HIGH TIDES II........................... 70,125
----------
Total................................ $ 126,044
==========
Interest Rate Swaps -- From time to time, we use interest rate swap
agreements to mitigate our exposure to interest rate fluctuations associated
with certain of our debt instruments and to adjust the mix between fixed and
floating rate debt in our capital structure to desired levels. We do not use
interest rate swap agreements for speculative or trading purposes. The following
tables summarize the fair market values of our existing interest rate swap
agreements as of June 30, 2004, (dollars in thousands):
Variable to fixed Swaps
Weighted Average Weighted Average
Notional Interest Rate Interest Rate Fair Market
Maturity Date Principal Amount (Pay) (Receive) Value
- -------------- ---------------- ---------------- ----------------- ---------------
2011.......... $ 58,178 4.5% 3-month US $LIBOR (887)
2011.......... 291,897 4.5% 3-month US $LIBOR (4,466)
2011.......... 209,833 4.4% 3-month US $LIBOR (2,741)
2011.......... 41,822 4.4% 3-month US $LIBOR (546)
2011.......... 40,746 6.9% 3-month US $LIBOR (4,305)
2012.......... 108,612 6.5% 3-month US $LIBOR (11,219)
2014.......... 58,682 6.7% 3-month US $LIBOR (5,832)
2016.......... 21,540 7.3% 3-month US $LIBOR (3,363)
2016.......... 14,360 7.3% 3-month US $LIBOR (2,242)
2016.......... 43,080 7.3% 3-month US $LIBOR (6,726)
2016.......... 28,720 7.3% 3-month US $LIBOR (4,484)
2016.......... 35,900 7.3% 3-month US $LIBOR (5,607)
----------- ---- ---------
Total...... $ 953,370 5.3% $ (52,418)
=========== === =========
Fixed to Variable Swaps
Weighted Average Weighted Average
Notional Interest Rate Interest Rate Fair Market
Maturity Date Principal Amount (Pay) (Receive) Value
- -------------- ---------------- ----------------- ----------------- --------------
2011.......... $ 100,000 6-month US $LIBOR 8.5% $ (8,548)
2011.......... 100,000 6-month US $LIBOR 8.5% (6,739)
2011.......... 200,000 6-month US $LIBOR 8.5% (13,838)
2011.......... 100,000 6-month US $LIBOR 8.5% (10,374)
----------- --- ---------
Total...... $ 500,000 8.5% $ (39,499)
=========== === =========
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The fair value of outstanding interest rate swaps and cross currency swaps
and the fair value that would be expected after a one percent adverse interest
rate change are shown in the table below (in thousands):
Variable to Fixed Swaps
Fair Value After a
1.0% (100 basis point)
Fair Value as of June 30, 2004 Adverse Interest Rate Change
------------------------------ ----------------------------
$ (52,418) $ (94,618)
Fixed to Variable Swaps
Fair Value After a
1.0% (100 basis point)
Fair Value as of June 30, 2004 Adverse Interest Rate Change
------------------------------ ----------------------------
$ (39,499) $ (67,378)
Currency Exposure. We own subsidiary entities in several countries. These
entities generally have functional currencies other than the U.S. dollar. In
most cases, the functional currency is consistent with the local currency of the
host country where the particular entity is located. In certain cases, we and
our foreign subsidiary entities hold monetary assets and/or liabilities that are
not denominated in the functional currencies referred to above. In such
instances, we apply the provisions of SFAS No. 52, "Foreign Currency
Translation," to account for the monthly re-measurement gains and losses of
these assets and liabilities into the functional currencies for each entity. In
some cases we can reduce our potential exposures to net income by designating
liabilities denominated in non-functional currencies as hedges of our net
investment in a foreign subsidiary or by entering into derivative instruments
and designating them in hedging relationships against a foreign exchange
exposure. Based on our unhedged exposures at June 30, 2004, the impact to our
pre-tax earnings that would be expected after a 10% adverse change in exchange
rates is shown in the table below (in thousands):
Impact to Pre-Tax Net Income
After 10% Adverse Exchange
Currency Exposure Rate Change
----------------- ----------------------------
GBP-Euro $ (21,895)
$C-$US (305)
$C-Euro (1,483)
Significant changes in exchange rates will also impact our Cumulative
Translation Adjustment ("CTA") balance when translating the financial statements
of our foreign operations from their respective functional currencies into our
reporting currency, the U.S. dollar. An example of the impact that significant
exchange rate movements can have on our Balance Sheet position occurred in 2003.
During 2003 CTA increased by approximately $200 million primarily due to a
weakening of the U.S. dollar of approximately 18% and 10% against the Canadian
dollar and Great British Pound, respectively.
Debt Financing -- Because of the significant capital requirements within
our industry, debt financing is often needed to fund our growth. Certain debt
instruments may affect us adversely because of changes in market conditions. We
have used two primary forms of debt which are subject to market risk: (1)
Variable rate construction/project financing and (2) Other variable-rate
instruments. Significant LIBOR increases could have a negative impact on our
future interest expense. Our variable-rate construction/project financing is
primarily through CalGen. Borrowings under this credit agreement are used
exclusively to fund the construction of our power plants. Other variable-rate
instruments consist primarily of our revolving credit and term loan facilities,
which are used for general corporate purposes. Both our variable-rate
construction/project financing and other variable-rate instruments are indexed
to base rates, generally LIBOR, as shown below.
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The following table summarizes our variable-rate debt exposed to interest
rate risk as of June 30, 2004. All outstanding balances and fair market values
are shown net of applicable premium or discount, if any (dollars in thousands):
Fair Value
2004(8) 2005 2006 2007 2008 Thereafter 6/30/2004(9)
------- -------- ------- ---------- ------- ---------- ------------
3-month US$LIBOR weighted average
interest rate basis (4)
First Priority Senior Secured Term Loan B
Notes Due 2007........................... $ 1,000 $ 2,000 $ 2,000 $ 193,500 $ -- $ -- $ 198,500
MEP Pleasant Hill Term Loan, Tranche A.... 2,275 6,700 7,482 8,132 9,271 95,235 129,096
------- -------- ------- ---------- ------- ---------- ----------
Total of 3-month US$LIBOR rate debt.... 3,275 8,700 9,482 201,632 9,271 95,235 327,596
1-month EURLIBOR weighted average
interest rate basis (4)
Thomassen revolving line of credit........ -- 3,147 -- -- -- -- 3,147
------- -------- ------- ---------- ------- ---------- ----------
Total of 1-month EURLIBOR rate debt.... -- 3,147 -- -- -- -- 3,147
1-month US$LIBOR weighted average
interest rate basis (4)
Corporate revolving line of credit........ -- 100,000 -- -- -- -- 100,000
First Priority Secured Floating
Rate Notes Due 2009 (CalGen)............. -- -- -- 1,175 2,350 231,475 235,000
CalGen Revolver........................... -- -- -- 54,500 -- -- 54,500
------- -------- ------- ---------- ------- ---------- ----------
Total of 1-month US$LIBOR rate debt.... -- 100,000 -- 55,675 2,350 231,475 389,500
6-month US$LIBOR weighted average
interest rate basis (4)
Third Priority Secured Floating
Rate Notes Due 2011 (CalGen)............. -- -- -- -- -- 680,000 680,000
------- -------- ------- ---------- ------- ---------- ----------
Total of 6-month US$LIBOR rate debt.... -- -- -- -- -- 680,000 680,000
5-month US$LIBOR weighted average
interest rate basis (4)
Riverside Energy Center project financing. -- 3,685 3,685 3,685 3,685 353,760 368,500
Rocky Mountain Energy Center project
financing................................ -- 2,649 2,649 2,649 2,649 254,304 264,900
------- -------- ------- ---------- ------- ---------- ----------
Total of 6-month US$LIBOR rate debt.... -- 6,334 6,334 6,334 6,334 608,064 633,400
(1)(4)
First Priority Secured Institutional
Term Loan Due 2009 (CCFC I).............. 1,711 3,208 3,208 3,208 3,208 365,242 379,785
Second Priority Senior Secured Floating
Rate Notes Due 2011 (CCFC I)............. -- -- -- -- -- 408,083 408,083
------- -------- ------- ---------- ------- ---------- ----------
Total of variable rate debt as defined
at (1) below.......................... 1,711 3,208 3,208 3,208 3,208 773,325 787,868
(2)(4)
Second Priority Senior Secured Term
Loan B Notes Due 2007.................... 3,750 7,500 7,500 725,625 -- -- 744,375
------- -------- ------- ---------- ------- ---------- ----------
Total of variable rate debt as defined
at (2) below.......................... 3,750 7,500 7,500 725,625 -- -- 744,375
(3)(4)
Second Priority Senior Secured Floating
Due 2007................................. 2,500 5,000 5,000 483,750 -- -- 496,250
Blue Spruce Energy Center project
financing................................ -- 1,875 3,750 3,750 3,750 106,675 119,800
------- -------- ------- ---------- ------- ---------- ----------
Total of variable rate debt as defined
at (3) below.......................... 2,500 6,875 8,750 487,500 3,750 106,675 616,050
(5)(4)
First Priority Secured Term Loans
Due 2009 (CalGen)........................ -- -- -- 3,000 6,000 591,000 600,000
Second Priority Secured Floating
Rate Notes Due 2010 (CalGen)............. -- -- -- -- 3,200 627,639 630,839
Second Priority Secured Term Loans
Due 2010 (CalGen)........................ -- -- -- -- 500 98,069 98,569
------- -------- ------- ---------- ------- ---------- ----------
Total of variable rate debt as defined
at (5) below.......................... -- -- -- 3,000 9,700 1,316,708 1,329,408
------- -------- ------- ---------- ------- ---------- ----------
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Fair Value
2004(8) 2005 2006 2007 2008 Thereafter 6/30/2004(9)
------- -------- ------- ---------- ------- ---------- ------------
(6)(4)
Island Cogen.............................. -- 5,947 -- -- -- -- 5,947
------- -------- ------- ---------- ------- ---------- ----------
Total of variable rate debt as defined
at (6) below.......................... -- 5,947 -- -- -- -- 5,947
(6)(4)
Contra Costa.............................. -- 168 175 182 190 1,561 2,276
------- -------- ------- ---------- ------- ---------- ----------
Total of variable rate debt as defined
at (6) below.......................... -- 168 175 182 190 1,561 2,276
------- -------- ------- ---------- ------- ---------- ----------
Grand total variable-rate debt
instruments......................... $11,236 $141,879 $35,449 $1,483,156 $34,803 $3,813,043 $5,519,567
======= ======== ======= ========== ======= ========== ==========
- ------------
<FN>
(1) British Bankers Association LIBOR Rate for deposit in US dollars for a
period of six months.
(2) U.S. prime rate in combination with the Federal Funds Effective Rate.
(3) British Bankers Association LIBOR Rate for deposit in US dollars for a
period of three months.
(4) Actual interest rates include a spread over the basis amount.
(5) Choice of 1-month US $LIBOR, 2-month US $LIBOR, 3-month US $LIBOR, 6-month
US $LIBOR, 12-month US $LIBOR or a base rate.
(6) Bankers Acceptance Rate.
(7) Local Agency Fund.
(8) For 6 months remaining in 2004.
(9) Fair value equals carrying value.
</FN>
Construction/project financing facility -- In November 2004 the $2.5
billion secured construction financing revolving facility for our wholly owned
subsidiary CCFC II (renamed CalGen) was scheduled to mature. On March 23, 2004,
CalGen completed its offering of secured institutional term loans and secured
notes, which refinanced the CCFC II facility. We realized total proceeds from
the offering in the amount of $2.4 billion, before transaction costs and fees.
Riverside Holdings, LLC and Rocky Mountain Energy Center, LLC refinancing
- -- On June 29, 2004, Rocky Mountain Energy Center, LLC and Riverside Energy
Center, LLC, wholly owned stand-alone subsidiaries of the Company's Calpine
Riverside Holdings, LLC subsidiary, received funding in the aggregate amount of
$661.5 million comprised of $633.4 million of First Priority Secured Floating
Rate Term Loans Due 2011 priced at LIBOR plus 425 basis points and $28.1 million
letter of credit-linked deposit. Net proceeds from the loans, after transaction
costs and fees, were used to pay final construction costs and refinance amounts
outstanding under the $250 million non-recourse project financing for the Rocky
Mountain facility and the $230 million non-recourse project financing for the
Riverside facility. See Note 8 of the Notes to Consolidated Condensed Financial
Statements.
New Accounting Pronouncements
In January 2003 FASB issued FIN 46. FIN 46 requires the consolidation of an
entity by an enterprise that absorbs a majority of the entity's expected losses,
receives a majority of the entity's expected residual returns, or both, as a
result of ownership, contractual or other financial interest in the entity.
Historically, entities have generally been consolidated by an enterprise when it
has a controlling financial interest through ownership of a majority voting
interest in the entity. The objectives of FIN 46 are to provide guidance on the
identification of Variable Interest Entities ("VIEs") for which control is
achieved through means other than ownership of a majority of the voting interest
of the entity, and how to determine which business enterprise (if any), as the
Primary Beneficiary, should consolidate the Variable Interest Entity ("VIE").
This new model for consolidation applies to an entity in which either (1) the
at-risk equity is insufficient to absorb expected losses without additional
subordinated financial support or (2) its at-risk equity holders as a group are
not able to make decisions that have a significant impact on the success or
failure of the entity's ongoing activities. A variable interest in a VIE, by
definition, is an asset, liability, equity, contractual arrangement or other
economic interest that absorbs the entity's variability.
-70-
In December 2003 FASB modified FIN 46 with FIN 46-R to make certain
technical corrections and to address certain implementation issues. FIN 46, as
originally issued, was effective immediately for VIEs created or acquired after
January 31, 2003. FIN 46-R delayed the effective date of the interpretation to
no later than March 31, 2004, (for calendar-year enterprises), except for
Special Purpose Entities ("SPEs") for which the effective date was December 31,
2003. We have adopted FIN 46-R for our investment in SPEs, equity method joint
ventures, our wholly owned subsidiaries that are subject to long-term power
purchase agreements and tolling arrangements, operating lease arrangements
containing fixed price purchase options and our wholly owned subsidiaries that
have issued mandatorily redeemable non-controlling preferred interests.
On application of FIN 46, we evaluated our investments in joint ventures
and operating lease arrangements containing fixed price purchase options and
concluded that, in some instances, these entities were VIEs. However, in these
instances, we were not the Primary Beneficiary, as we would not absorb a
majority of these entities' expected variability. An enterprise that holds a
significant variable interest in a VIE is required to make certain disclosures
regarding the nature and timing of its involvement with the VIE and the nature,
purpose, size and activities of the VIE. The fixed price purchase options under
our operating lease arrangements were not considered significant variable
interests. However, our investments in joint ventures were considered
significant. See Note 5 of the Notes to Consolidated Condensed Financial
Statements for more information related to these joint venture investments.
An analysis was performed for 100% Company-owned subsidiaries with
significant long-term power sales or tolling agreements. Certain of the 100%
Company-owned subsidiaries were deemed to be VIEs by virtue of a power sales or
tolling agreement which was longer than 10 years and for more than 50% of the
entity's capacity. However, in all cases, we absorbed a majority of the entity's
variability and continue to consolidate these 100% Company-owned subsidiaries.
We qualitatively determined that power sales or tolling agreements less than 10
years in length and for less than 50% of the entity's capacity would not cause
the power purchaser to be the Primary Beneficiary, due to the length of the
economic life of the underlying assets. Also, power sales and tolling agreements
meeting the definition of a lease under EITF Issue No. 01-08, "Determining
Whether an Arrangement Contains a Lease," were not considered variable interests
due to certain exclusions under FIN 46-R.
A similar analysis was performed for our wholly owned subsidiaries that
have issued mandatorily redeemable non-controlling preferred interests. These
entities were determined to be VIEs in which we absorb the majority of the
variability, primarily due to the debt characteristics of the preferred
interest, which are classified as debt in accordance with SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity" in our Consolidated Condensed Balance Sheets.
Consequently, we continue to consolidate these wholly owned subsidiaries. See
Note 2 of the Notes to Consolidated Condensed Financial Statements for more
information.
On July 19, 2004, the Emerging Issues Task Force ("EITF") reached a
tentative conclusion on Issue No. 04-8 ("EITF 04-8"): "The Effect of
Contingently Convertible Debt on Diluted Earnings per Share" that would require
companies that have issued contingently convertible debt instruments, commonly
referred to as "Co-Cos," with a market price trigger to include the effects of
the conversion in earnings per share ("EPS"), regardless of whether the price
trigger had been met. Currently, Co-Cos are not included in EPS if the price
trigger has not been met. Typically, the affected instruments are convertible
into common shares of the issuer after the common stock price has exceeded a
predetermined threshold for a specified time period. If EITF 04-8 is finalized
as currently written, our $900 million of 4.75% Contingent Convertible Senior
Notes Due 2023 may be affected. We are still in the process of determining what
impact, if any, this new guidance will have on our diluted EPS.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in Item 2.
Item 4. Controls and Procedures.
As reported in the Company's Form 10-K filing for the year ended December
31, 2003, in connection with the audit of the Company's financial statements for
the fiscal year ended December 31, 2003, its independent registered public
accounting firm reviewed the Company's information systems control framework and
identified to the Company certain significant deficiencies in the design of such
systems. These design deficiencies generally related to the number of persons
having access to certain of the Company's information systems databases, as well
as the segregation of duties of persons with such access. The Company has
concluded that, in the aggregate, these deficiencies constituted a material
weakness in its internal control over financial reporting, and the Company has
performed substantial analytical and post-closing procedures as a result of
these design deficiencies. Based on the Company's compensating controls and
testing, it has concluded that these design deficiencies did not result in any
material errors in its financial statements. Additionally, the Company has
-71-
completed the process of correcting these design deficiencies by taking the
following steps:
o manual procedures have been replaced with system-based controls to ensure
proper segregation of duties and documentation of approval for the Journal
Entry and Vendor Maintenance processes; and
o system access rights for financial system software updates have been
redefined and restricted to segregate certain activities and allow user
activities to be monitored.
The Company continues to test the effectiveness of these changes.
Other than correcting the material control weakness identified above, there
were no other changes in the Company's internal controls over financial
reporting identified in connection with the evaluation required by paragraph (d)
of Rule 13a-15 or Rule 15d-15 that have materially affected, or are reasonably
likely to materially affect, the Company's internal controls over financial
reporting.
The Company's Chief Executive Officer and Chief Financial Officer, based on
the evaluation of the Company's disclosure controls and procedures (as defined
in Rules 13a-15(e) and 15d-15(e) of the Securities and Exchange Act of 1934, as
amended) required by paragraph (b) of Rule 13a-15 or Rule 15d-15, as of June 30,
2004, and taking into account the material weakness described above including
the analysis and testing performed by the Company, have concluded that the
Company's disclosure controls and procedures were effective to ensure the timely
collection, evaluation and disclosure of information relating to the Company
that would potentially be subject to disclosure under the Securities Exchange
Act of 1934, as amended, and the rules and regulations promulgated thereunder.
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings.
We are party to various litigation matters arising out of the normal course
of business, the more significant of which are summarized below. The ultimate
outcome of each of these matters cannot presently be determined, nor can the
liability that could potentially result from a negative outcome be reasonably
estimated presently for every case. The liability we may ultimately incur with
respect to any one of these matters in the event of a negative outcome may be in
excess of amounts currently accrued with respect to such matters and, as a
result of these matters, may potentially be material to our Consolidated
Condensed Financial Statements.
Securities Class Action Lawsuits. Since March 11, 2002, fourteen
shareholder lawsuits have been filed against Calpine and certain of its officers
in the United States District Court for the Northern District of California. The
actions captioned Weisz v. Calpine Corp., et al., filed March 11, 2002, and
Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002, are
purported class actions on behalf of purchasers of Calpine stock between March
15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18,
2002, is a purported class action on behalf of purchasers of Calpine stock
between February 6, 2001 and December 13, 2001. The eleven other actions,
captioned Local 144 Nursing Home Pension Fund v. Calpine Corp., Lukowski v.
Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., Laborers Local
1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta
v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp., and Rose v.
Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The
complaints in these eleven actions are virtually identical-- they are filed by
three law firms, in conjunction with other law firms as co-counsel. All eleven
lawsuits are purported class actions on behalf of purchasers of Calpine's
securities between January 5, 2001 and December 13, 2001.
The complaints in these fourteen actions allege that, during the purported
class periods, certain Calpine executives issued false and misleading statements
about Calpine's financial condition in violation of Sections 10(b) and 20(1) of
the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek
an unspecified amount of damages, in addition to other forms of relief.
In addition, a fifteenth securities class action, Ser v. Calpine, et al.,
was filed on May 13, 2002. The underlying allegations in the Ser action are
substantially the same as those in the above-referenced actions. However, the
Ser action is brought on behalf of a purported class of purchasers of Calpine's
8.5% Senior Notes Due February 15, 2011 ("2011 Notes") and the alleged class
period is October 15, 2001 through December 13, 2001. The Ser complaint alleges
that, in violation of Sections 11 and 15 of the Securities Act of 1933, the
Supplemental Prospectus for the 2011 Notes contained false and misleading
statements regarding Calpine's financial condition. This action names Calpine,
certain of its officers and directors, and the underwriters of the 2011 Notes
offering as defendants, and seeks an unspecified amount of damages, in addition
to other forms of relief.
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All fifteen of these securities class action lawsuits were consolidated in
the United States District Court for the Northern District of California.
Plaintiffs filed a first amended complaint in October 2002. The amended
complaint did not include the 1933 Act complaints raised in the bondholders'
complaint, and the number of defendants named was reduced. On January 16, 2003,
before our response was due to this amended complaint, plaintiffs filed a
further second complaint. This second amended complaint added three additional
Calpine executives and Arthur Andersen LLP as defendants. The second amended
complaint set forth additional alleged violations of Section 10 of the
Securities Exchange Act of 1934 relating to allegedly false and misleading
statements made regarding Calpine's role in the California energy crisis, the
long term power contracts with the California Department of Water Resources, and
Calpine's dealings with Enron, and additional claims under Section 11 and
Section 15 of the Securities Act of 1933 relating to statements regarding the
causes of the California energy crisis. We filed a motion to dismiss this
consolidated action in early April 2003.
On August 29, 2003, the judge issued an order dismissing, with leave to
amend, all of the allegations set forth in the second amended complaint except
for a claim under Section 11 of the Securities Act relating to statements
relating to the causes of the California energy crisis and the related increase
in wholesale prices contained in the Supplemental Prospectuses for the 2011
Notes.
The judge instructed plaintiff, Julies Ser, to file a third amended
complaint, which he did on October 17, 2003. The third amended complaint names
Calpine and three executives as defendants and alleges the Section 11 claim that
survived the judge's August 29, 2003 order.
On November 21, 2003, Calpine and the individual defendants moved to
dismiss the third amended complaint on the grounds that plaintiff's Section 11
claim was barred by the applicable one-year statute of limitations. On February
4, 2004, the judge denied the motion to dismiss but has asked the parties to be
prepared to file summary judgment motions to address the statute of limitations
issue. We filed our answer to the third amended complaint on February 28, 2004.
In a separate order dated February 4, 2004, the court denied without
prejudice Julies Ser's motion to be appointed lead plaintiff. Mr. Ser
subsequently stated he no longer desired to serve as lead plaintiff. On April 4,
2004, the Policemen and Firemen Retirement System of the City of Detroit ("P&F")
moved to be appointed lead plaintiff which motion was granted on May 14, 2004.
We consider the lawsuit to be without merit and we intend to continue to
defend vigorously against these allegations.
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities
class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was
filed on March 11, 2003, against Calpine, its directors and certain investment
banks in state superior court of San Diego County, California. The underlying
allegations in the Hawaii Structural Ironworkers Pension Fund action ("Hawaii
action") are substantially the same as the federal securities class actions
described above. However, the Hawaii action is brought on behalf of a purported
class of purchasers of Calpine's equity securities sold to public investors in
its April 2002 equity offering. The Hawaii action alleges that the Registration
Statement and Prospectus filed by Calpine which became effective on April 24,
2002, contained false and misleading statements regarding Calpine's financial
condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933.
The Hawaii action relies in part on Calpine's restatement of certain past
financial results, announced on March 3, 2003, to support its allegations. The
Hawaii action seeks an unspecified amount of damages, in addition to other forms
of relief.
We removed the Hawaii action to federal court in April 2003 and filed a
motion to transfer the case for consolidation with the other securities class
action lawsuits in the United States District Court for the Northern District of
California in May 2003. Plaintiff sought to have the action remanded to state
court, and on August 27, 2003, the United States District Court for the Southern
District of California granted plaintiff's motion to remand the action to state
court. In early October 2003 plaintiff agreed to dismiss the claims it has
against three of the outside directors.
On November 5, 2003, Calpine, the individual defendants and the underwriter
defendants filed motions to dismiss this complaint on numerous grounds. On
February 6, 2004, the court issued a tentative ruling sustaining our motion to
dismiss on the issue of plaintiff's standing. The court found that plaintiff had
not shown that it had purchased Calpine stock "traceable" to the April 2002
equity offering. The court overruled our motion to dismiss on all other grounds.
On March 12, 2004, after oral argument on the issues, the court confirmed its
February 2, 2004, ruling.
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On February 20, 2004, plaintiff filed an amended complaint, and in late
March 2004 Calpine and the individual defendants filed answers to this
complaint. On April 9, 2004, we and the individual defendants filed motions to
transfer the lawsuit to Santa Clara County Superior Court, which motions were
granted on May 7, 2004. We consider this lawsuit to be without merit and intend
to continue to defend vigorously against it.
Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in
the Calpine Corporation Retirement Savings Plan (the "401(k) Plan") filed a
class action lawsuit in the United States District Court for the Northern
District of California. The underlying allegations in this action ("Phelps
action") are substantially the same as those in the securities class actions
described above. However, the Phelps action is brought on behalf of a purported
class of participants in the 401(k) Plan. The Phelps action alleges that various
filings and statements made by Calpine during the class period were materially
false and misleading, and that defendants failed to fulfill their fiduciary
obligations as fiduciaries of the 401(k) Plan by allowing the 401(k) Plan to
invest in Calpine common stock. The Phelps action seeks an unspecified amount of
damages, in addition to other forms of relief. In May 2003, Lennette
Poor-Herena, another participant in the 401(k) Plan, filed a substantially
similar class action lawsuit as the Phelps action also in the Northern District
of California. Plaintiffs' counsel is the same in both of these actions, and
they have agreed to consolidate these two cases and to coordinate them with the
consolidated federal securities class actions described above. On January 20,
2004, plaintiff James Phelps filed a consolidated ERISA complaint naming Calpine
and numerous individual current and former Calpine Board members and employees
as defendants. Pursuant to a stipulated agreement with plaintiff, Calpine's
response to the amended complaint is due on August 13, 2004. We consider this
lawsuit to be without merit and intend to vigorously defend against it.
Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder
filed a derivative lawsuit on behalf of Calpine against its directors and one of
its senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. and
is pending in state superior court of Santa Clara County, California. Calpine is
a nominal defendant in this lawsuit, which alleges claims relating to
purportedly misleading statements about Calpine and stock sales by certain of
the director defendants and the officer defendant. In December 2002 the court
dismissed the complaint with respect to certain of the director defendants for
lack of personal jurisdiction, though plaintiff may appeal this ruling. In early
February 2003 plaintiff filed an amended complaint. In March 2003 Calpine and
the individual defendants filed motions to dismiss and motions to stay this
proceeding in favor of the federal securities class actions described above. In
July 2003 the court granted the motions to stay this proceeding in favor of the
consolidated federal securities class actions described above. We cannot
estimate the possible loss or range of possible loss from this matter. We
consider this lawsuit to be without merit and intend to vigorously defend
against it.
Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a
derivative suit in the United States District Court for the Northern District of
California on behalf of Calpine against its directors, captioned Gordon v.
Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to
dismiss the action against certain of the director defendants on the grounds of
lack of personal jurisdiction, as well as to dismiss the complaint in total on
other grounds. In February 2003 plaintiff agreed to stay these proceedings in
favor of the consolidated federal securities class action described above and to
dismiss without prejudice certain director defendants. On March 4, 2003,
plaintiff filed papers with the court voluntarily agreeing to dismiss without
prejudice the claims he had against three of the outside directors. We cannot
estimate the possible loss or range of possible loss from this matter. We
consider this lawsuit to be without merit and intend to continue to defend
vigorously against it.
Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, Calpine
sued Automated Credit Exchange ("ACE") in state superior court of Alameda
County, California for negligence and breach of contract to recover reclaim
trading credits, a form of emission reduction credits that should have been held
in Calpine's account with U.S. Trust Company ("US Trust"). Calpine wrote off
$17.7 million in December 2001 related to losses that it alleged were caused by
ACE. Calpine and ACE entered into a Settlement Agreement on March 29, 2002,
pursuant to which ACE made a payment to Calpine of $7 million and transferred to
Calpine the rights to the emission reduction credits to be held by ACE. We
recognized the $7 million as income in the second quarter of 2002. In June 2002
a complaint was filed by InterGen North America, L.P. ("InterGen") against Anne
M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity,
which filed for bankruptcy protection on May 6, 2002. InterGen alleges it
suffered a loss of emission reduction credits from EonXchange in a manner
similar to Calpine's loss from ACE. InterGen's complaint alleges that Anne
Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and
that ACE and other Sholtz entities should be deemed to be one economic
enterprise and all retroactively included in the EonXchange bankruptcy filing as
of May 6, 2002. By a judgment entered on October 30, 2002, the bankruptcy court
consolidated ACE and the other Sholtz controlled entities with the bankruptcy
estate of EonXchange. Subsequently, the Trustee of EonXchange filed a separate
motion to substantively consolidate Anne Sholtz into the bankruptcy estate of
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EonXchange. Although Anne Sholtz initially opposed such motion, she entered into
a settlement agreement with the Trustee consenting to her being substantively
consolidated into the bankruptcy proceeding. The bankruptcy court entered an
order approving Anne Sholtz's settlement agreement with the Trustee on April 3,
2002. On July 10, 2003, Howard Grobstein, the Trustee in the EonXchange
bankruptcy, filed a complaint for avoidance against Calpine, seeking recovery of
the $7 million (plus interest and costs) paid to Calpine in the March 29, 2002
Settlement Agreement. The complaint claims that the $7 million received by
Calpine in the Settlement Agreement was transferred within 90 days of the filing
of bankruptcy and therefore should be avoided and preserved for the benefit of
the bankruptcy estate. On August 28, 2003, Calpine filed its answer denying that
the $7 million is an avoidable preference. Following two settlement conferences,
on or about May 21, 2004, Calpine and the Trustee entered into a Settlement
Agreement, whereby Calpine agreed to pay $5.85 million, which was approved by
the Bankruptcy Court on June 16, 2004. The preference lawsuit will be dismissed
with prejudice upon final payment of the settlement, which will occur on October
1, 2004.
International Paper Company v. Androscoggin Energy LLC. In October 2000
International Paper Company ("IP") filed a complaint in the United States
District Court for the Northern District of Illinois against Androscoggin Energy
LLC ("AELLC") alleging that AELLC breached certain contractual representations
and warranties by failing to disclose facts surrounding the termination,
effective May 8, 1998, of one of AELLC's fixed-cost gas supply agreements. We
had acquired a 32.3% interest in AELLC as part of the SkyGen transaction which
closed in October 2000. AELLC filed a counterclaim against IP that has been
referred to arbitration that AELLC may commence at its discretion upon further
evaluation. On November 7, 2002, the court issued an opinion on the parties'
cross motions for summary judgment finding in AELLC's favor on certain matters
though granting summary judgment to IP on the liability aspect of a particular
claim against AELLC. The court also denied a motion submitted by IP for
preliminary injunction to permit IP to make payment of funds into escrow (not
directly to AELLC) and require AELLC to post a significant bond.
In mid-April of 2003 IP unilaterally availed itself to self-help in
withholding amounts in excess of $2.0 million as a set-off for litigation
expenses and fees incurred to date as well as an estimated portion of a rate
fund to AELLC. Upon AELLC's amended complaint and request for immediate
injunctive relief against such actions, the court ordered that IP must pay the
approximately $1.2 million withheld as attorneys' fees related to the litigation
as any such perceived entitlement was premature, but deferred to provide
injunctive relief on the incomplete record concerning the offset of $799,000 as
an estimated pass-through of the rate fund. IP complied with the order on April
29, 2003, and tendered payment to AELLC of the approximately $1.2 million. On
June 26, 2003, the court entered an order dismissing AELLC's amended
counterclaim without prejudice to AELLC refiling the claims as breach of
contract claims in a separate lawsuit. On December 11, 2003, the court denied in
part IP's summary judgment motion pertaining to damages. In short, the court:
(i) determined that, as a matter of law, IP is entitled to pursue an action for
damages as a result of AELLC's breach, and (ii) ruled that sufficient questions
of fact remain to deny IP summary judgment on the measure of damages as IP did
not sufficiently establish causation resulting from AELLC's breach of contract
(the liability aspect of which IP obtained a summary judgment in December 2002).
On February 2, 2004, the parties filed a Final Pretrial Order with the court.
The case appears likely scheduled for trial in the third quarter of 2004,
subject to the court's discretion and calendar. We believe we have adequately
reserved for the possible loss, if any, we may ultimately incur as a result of
this matter.
Pacific Gas and Electric Company v. Calpine Corporation, et al. On July 22,
2003, PG&E filed with the CPUC a Complaint of PG&E and Request for Immediate
Issuance of an Order to Show Cause ("complaint") against Calpine Corporation,
CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas
Company, and Lodi Gas Storage, LLC ("LGS"). The complaint requests the CPUC to
issue an order requiring defendants to show cause why they should not be ordered
to cease and desist from using any direct interconnections between the
facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek
and obtain regulatory approval from the CPUC. The complaint also seeks an order
directing defendants to pay to PG&E any underpayments of PG&E's tariffed
transportation rates and to make restitution for any profits earned from any
business activity related to LGS' direct interconnections to any entity other
than PG&E. The complaint further alleges that various natural gas consumers,
including Calpine affiliated generation projects within California, are engaged
with defendants in the acts complained of, and that the defendants unlawfully
bypass PG&E's system and operate as an unregulated local distribution company
within PG&E's service territory. On August 27, 2003, Calpine filed its answer
and a motion to dismiss. LGS also made similar filings. On October 16, 2003, the
presiding administrative law judge denied the motion to dismiss and on October
24, 2003, issued a Scoping Memo and Ruling establishing a procedural schedule
and set the matter for an evidentiary hearing. On January 15, 2004, Calpine, LGS
and PG&E executed a Settlement Agreement to resolve all outstanding allegations
and claims raised in the complaint. Certain aspects of the Settlement Agreement
are effective immediately and the effectiveness of other provisions is subject
to the approval of the Settlement Agreement by the CPUC. In the event the CPUC
fails to approve the Settlement Agreement, its operative terms and conditions
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become null and void. The Settlement Agreement provides, in part, for: 1) PG&E
to be paid $2.7 million; 2) the disconnection of the LGS interconnections with
Calpine; 3) Calpine to obtain PG&E consent or regulatory or other governmental
approval before resuming any sales or exchanges at the Ryer Island Meter
Station; 4) PG&E's withdrawal of its public utility claims against Calpine; and
5) no party admitting any wrongdoing. Accordingly, the presiding administrative
law judge vacated the hearing schedule and established a new procedural schedule
for the filing of the Settlement Agreement. On February 6, 2004, the Settlement
Agreement was filed with the CPUC. The parties were given the opportunity to
submit comments and reply comments on the Settlement Agreement. The CPUC
approved the Settlement Agreement on July 8, 2004 and the $2.7 million was paid
to PG&E on July 15, 2004.
Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On
November 5, 2003, Panda Energy International, Inc. and certain related parties,
including PLC II, LLC, (collectively "Panda") filed suit against Calpine and
certain of its affiliates in the United States District Court for the Northern
District of Texas, alleging, among other things, that we breached duties of care
and loyalty allegedly owed to Panda by failing to correctly construct and
operate the Oneta Energy Center ("Oneta"), which we acquired from Panda, in
accordance with Panda's original plans. Panda alleges that it is entitled to a
portion of the profits from Oneta plant and that Calpine's actions have reduced
the profits from Oneta plant thereby undermining Panda's ability to repay monies
owed to Calpine on December 1, 2003, under a promissory note on which
approximately $38.6 million (including interest) is currently outstanding and
past due. The note is collateralized by Panda's carried interest in the income
generated from Oneta, which achieved full commercial operations in June 2003. We
have filed a counterclaim against Panda Energy International, Inc. (and PLC II,
LLC) based on a guaranty, and have also filed a motion to dismiss as to the
causes of action alleging federal and state securities laws violations. The
motion to dismiss is currently pending before the court. However, at the present
time, we cannot estimate the potential loss, if any, that might arise from this
matter. We consider Panda's lawsuit to be without merit and intend to defend
vigorously against it. We stopped accruing interest income on the promissory
note due December 1, 2003, as of the due date because of Panda's default in
repayment of the note.
California Business & Professions Code Section 17200 Cases, of which the
lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C.,
et al. This purported class action complaint filed in May 2002 against twenty
energy traders and energy companies, including CES, alleges that defendants
exercised market power and manipulated prices in violation of California
Business & Professions Code Section 17200 et seq., and seeks injunctive relief,
restitution, and attorneys' fees. We also have been named in seven other similar
complaints for violations of Section 17200. All seven cases were removed from
the various state courts in which they were originally filed to federal court
for pretrial proceedings with other cases in which we are not named as a
defendant. However, at the present time, we cannot estimate the potential loss,
if any, that might arise from this matter. We consider the allegations to be
without merit, and filed a motion to dismiss on August 28, 2003. The court
granted the motion, and plaintiffs have appealed.
Prior to the motion to dismiss being granted, one of the actions, captioned
Millar v. Allegheny Energy Supply Co., LLP, et al., was remanded to state
superior court of Alameda County, California. On January 12, 2004, CES was added
as a defendant in Millar. This action includes similar allegations to the other
17200 cases, but also seeks rescission of the long-term power contracts with
CDWR.
Upon motion from another newly added defendant, Millar was recently removed
to federal court. It has now been transferred to the same judge that is
presiding over the other 17200 cases described above, where it will be
consolidated with such cases for pretrial purposes. We anticipate filing a
timely motion for dismissal of Millar as well.
Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy
Services, L.P. before the FERC, filed on December 4, 2001. Nevada Section 206
Complaint. On December 4, 2001, Nevada Power Company ("NPC") and Sierra Pacific
Power Company ("SPPC") filed a complaint with FERC under Section 206 of the
Federal Power Act against a number of parties to their power sales agreements,
including Calpine. NPC and SPPC allege in their complaint, which seeks a refund,
that the prices they agreed to pay in certain of the power sales agreements,
including those signed with Calpine, were negotiated during a time when the
power market was dysfunctional and that they are unjust and unreasonable. The
administrative law judge issued an Initial Decision on December 19, 2002, that
found for Calpine and the other respondents in the case and denied NPC the
relief that it was seeking. In June 2003, FERC rejected the complaint. Some
plaintiffs appealed to the FERC and their request for rehearing was denied. The
matter is pending on appeal before the United States Court of Appeals for the
Ninth Circuit and is in the pleading stage.
Transmission Service Agreement with Nevada Power. On March 16, 2004, NPC
filed a petition for declaratory order at FERC (Docket No. EL04-90-000) asking
that an order be issued requiring Calpine and Reliant Energy Services, Inc. to
pay for transmission service under their Transmission Service Agreements
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("TSAs") with NPC or, if the TSAs are terminated, to pay the lesser of the
transmission charges or a pro rata share of the total cost of NPC's Centennial
Project (approximately $33 million for Calpine). Calpine had previously provided
security to NPC for these costs in the form of a surety bond issued by Fireman's
Fund Insurance Company ("FFIC"). The Centennial Project involves construction of
various transmission facilities in two phases; Calpine's Moapa Energy Center
("MEC") is scheduled to receive service under its TSA from facilities yet to be
constructed in the second phase of the Centennial Project. Calpine has filed a
protest to the petition asserting that Calpine will take service under the TSA
if NPC proceeds to execute a purchase power agreement ("PPA") with MEC based on
its winning bid in the Request for Proposals that NPC conducted in 2003. Calpine
also has taken the position that if NPC does not execute a PPA with MEC, it will
terminate the TSA and any payment by Calpine would be limited to a pro rata
allocation of costs incurred to date on the second phase of the project
(approximately $4.5 million in total) among the three customers to be served. At
this time, we are unable to predict the final outcome of this proceeding or its
impact on us.
On or about April 27, 2004, NPC alleged to FFIC that Calpine had defaulted
on the TSA and made demand on FFIC for the full amount of the surety bond,
$33,333,333.00. On April 29, 2004, FFIC filed a complaint for declaratory order
in state superior court of Marin County, California in connection with this
demand.
FFIC's complaint asks that an order be issued declaring that it has no
obligation to make payment under the bond. Further, if the court determines that
FFIC does have an obligation to make payment, FFIC asks that an order be issued
declaring that (i) Calpine has an obligation to replace it with funds equal to
the amount of NPC's demand against the bond and (ii) Calpine is obligated to
indemnify and hold FFIC harmless for all loss, costs and fees incurred as a
result of the issuance of the bond. Calpine has filed its answer to the
complaint arguing, among other items, that it did not default on its obligations
under the TSA and therefore NPC is not entitled to make a demand upon the FFIC
bond. At this time, we are unable to predict the outcome of this proceeding or
its impact on us.
Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6,
2002, Calpine Canada Natural Gas Partnership ("Calpine Canada") filed a
complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp.
("Enron Canada") owed it approximately $1.5 million from the sale of gas in
connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron
Canada has not sought bankruptcy relief and has counterclaimed in the amount of
$18 million. Discovery is currently in progress, and we believe that Enron
Canada's counterclaim is without merit and intend to vigorously defend against
it.
Jones v. Calpine Corporation. On June 11, 2003, the Estate of Darrell Jones
and the Estate of Cynthia Jones filed a complaint against Calpine in the United
States District Court for the Western District of Washington. Calpine purchased
Goldendale Energy, Inc., a Washington corporation, from Darrell Jones. The
agreement provided, among other things, that upon substantial completion of the
Goldendale facility, Calpine would pay Mr. Jones (i) $6.0 million and (ii) $18.0
million less $0.2 million per day for each day that elapsed between July 1,
2002, and the date of substantial completion. Substantial completion of the
Goldendale facility has not occurred and the daily reduction in the payment
amount has reduced the $18.0 million payment to zero. The complaint alleges that
by not achieving substantial completion by July 1, 2002, Calpine breached its
contract with Mr. Jones, violated a duty of good faith and fair dealing, and
caused an inequitable forfeiture. The complaint seeks damages in an unspecified
amount in excess of $75,000. On July 28, 2003, Calpine filed a motion to dismiss
the complaint for failure to state a claim upon which relief can be granted. The
court granted Calpine's motion to dismiss the complaint on March 10, 2004.
Plaintiffs have filed a motion for reconsideration of the decision, which was
denied. Subsequently, on June 7, 2004, plaintiffs filed a notice of appeal.
Calpine also filed a motion to recover attorneys' fees from NESCO, which was
recently granted at a reduced amount. Calpine still, however, expects to make
the $6.0 million payment to the estates when the project is completed.
In addition, we are involved in various other claims and legal actions
arising out of the normal course of our business. We do not expect that the
outcome of these proceedings will have a material adverse effect on our
financial position or results of operations.
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities.
During the second quarter the Company issued unregistered shares of its
common stock in exchange for its HIGH TIDES, which are exchangeable for common
stock, as follows:
o On June 28, 2004, the Company exchanged 4.3 million shares of Calpine
common stock in privately negotiated transactions for approximately $20.0
million par value of HIGH TIDES I.
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o On June 29, 2004, the Company exchanged 5.4 million shares of Calpine
common stock in privately negotiated transactions for approximately $25.0
million par value of HIGH TIDES II.
o On June 30, 2004, the Company exchanged 10.4 million shares of Calpine
common stock in privately negotiated transactions for approximately $50.0
million par value HIGH TIDES II.
All of the shares of Calpine common stock issued in exchange for the HIGH
TIDES were issued without registration under the Securities Act of 1933 in
reliance upon the exemption afforded by Section 3(a)(9) thereof.
The following table sets forth the total units of HIGH TIDES purchased by
the Company during the second quarter, which are the only equity securities, or
securities convertible into equity securities, of the Company were purchased by
it during the period. All such purchases were made in privately negotiated
transactions.
Total Number of Maximum Number
Units Purchased as of Units that May
Part of Publicly Yet Be Purchased
Total Number of Average Price Paid Announced Plans Under the Plans
Period Units Purchased Per Share or Programs or Programs
- -------------- --------------- ------------------ ----------------- -----------------
4/1/04-4/30/04......... -- -- -- --
5/1/04-5/31/04......... -- -- -- --
6/1/04-6/30/04......... 1,900,000 $48.08 -- --
Item 4. Submission of Matters to a Vote of Security Holders.
Our Annual Meeting of Stockholders was held on May 26, 2004 (the "Annual
Meeting"), in Aptos, California. At the Annual Meeting, the stockholders voted
on the following matters: (i) the proposal to elect three Class II Directors to
the Board of Directors for a term of three years expiring in 2007, (ii) the
proposal to amend the Company's Amended and Restated Certificate of
Incorporation to increase the number of authorized shares of Common Stock, par
value $.001 per share ("Common Stock"), (iii) the proposal to amend the
Company's 1996 Stock Incentive Plan to increase the number of shares of the
Company's Common Stock available for grants of options and other stock-based
awards under such plan, (iv) the proposal to amend the Company's 2000 Employee
Stock Purchase Plan to increase the number of shares of the Company's Common
Stock available for grants of purchase rights under such plan, (v) three
stockholder proposals regarding (a) the Company's geothermal development
activities in the Medicine Lake Highlands and a request that the Company adopt
an indigenous peoples policy, (b) the Company's senior executive equity
compensation plans, and (c) stockholder voting, and (iv) the proposal to ratify
the appointment of PricewaterhouseCoopers LLP as independent accountants for the
Company for the fiscal year ending December 31, 2004.
The stockholders elected management's nominees as the Class II Directors in
an uncontested election, approved amending the Company's Amended and Restated
Certificate of Incorporation, approved amending the Company's 1996 Stock
Incentive Plan, approved amending the Company's 2000 Employee Stock Purchase
Plan, did not approve the stockholder proposal requesting that the Company cease
its geothermal development activities in the Medicine Lake Highlands and that
the Company adopt an indigenous peoples policy, did not approve the stockholder
proposal regarding the Company's senior executive equity compensation plans, did
not approve the stockholder proposal regarding stockholder voting, and ratified
the appointment of independent accountants by the following votes, respectively:
(i) Election of Ann B. Curtis as Class II Director for a three-year term
expiring 2007: 340,549,179 FOR and 39,650,521 WITHHELD;
Election of Kenneth T. Derr as Class II Director for a three-year term
expiring 2007: 340,944,921 FOR and 39,254,779 WITHHELD;
Election of Gerald Greenwald as Class II Director for a three-year term
expiring 2007: 340,885,215 FOR and 39,314,485 WITHHELD;
(ii) Proposal to amend the Company's Amended and Restated Certificate of
Incorporation to increase the number of authorized shares of Common
Stock: 344,016,567 FOR, 33,379,497 AGAINST, and 2,803,636 ABSTAIN
(iii) Proposal to amend the Company's 1996 Stock Incentive Plan to increase the
number of shares of the Company's Common Stock available for grants of
options and other stock-based awards under such plan: 112,195,541 FOR,
80,997,504 AGAINST, 2,687,696 ABSTAIN, and 184,318,959 Broker non-votes,
(iv) Proposal to amend the Company's 2000 Employee Stock Purchase Plan to
increase the number of shares of the Company's Common Stock available for
grants of purchase rights under such plan: 172,353,952 FOR, 20,788,375
AGAINST, 2,738,414 ABSTAIN, and 184,318,959 Broker non-votes
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(v) Proposal that the Company cease and desist geothermal development
activities in the Medicine Lake Highlands and requesting the Company to
adopt an indigenous peoples policy: 8,250,567 FOR, 181,409,173 AGAINST,
6,220,001 ABSTAIN, and 184,318,959 Broker non-votes;
(vi) Proposal that the Company's Compensation Committee of its Board of
Directors utilize performance and time-based restricted share programs in
lieu of stock options in developing future senior executive equity
compensation plans: 33,255,357 FOR, 158,444,552 AGAINST, 4,179,832
ABSTAIN, and 184,319,959 Broker non-votes;
(vii) Proposal requesting the Company's Board of Directors to study and report
on the feasibility of enabling stockholders to imitate the voting
decisions of an institutional investor: 17,537,323 FOR, 173,771,064
AGAINST, 4,571,354 ABSTAIN, and 184,319,959 Broker non-votes;
(viii) Ratification of the appointment of PricewaterhouseCoopers LLP as
independent accountants for the fiscal year ending December 31, 2004:
369,214,181, FOR, 8,353,462 AGAINST, and 2,631,557 ABSTAIN.
The three-year terms of Class III and Class II Directors continued after
the Annual Meeting and will expire in 2005 and 2006, respectively. The Class III
Directors are Susan C. Schwab, Susan Wang and Peter Cartwright. The Class I
Directors are Jeffrey E. Garten, George J. Stathakis, and John O. Wilson.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
Exhibit
Number Description
- ------- ---------------------------------------------------------------------
+3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation, as amended through June 2, 2004.
*3.2 Amended and Restated By-laws of Calpine Corporation.(a)
*4.1.1 Indenture, dated as of May 16, 1996, between the Company and U.S.
Bank (as successor trustee to Fleet National Bank), as Trustee,
including form of Notes.(b)
*4.1.2 First Supplemental Indenture, dated as of August 1, 2000, between the
Company and U.S. Bank National Association (as successor trustee to
Fleet National Bank), as Trustee.(c)
*4.1.3 Second Supplemental Indenture, dated as of April 26, 2004, between
the Company and U.S. Bank National Association (as successor trustee
to Fleet National Bank), as Trustee.(d)
*4.2.1 Indenture, dated as of July 8, 1997, between the Company and The Bank
of New York, as Trustee, including form of Notes.(e)
*4.2.2 Supplemental Indenture, dated as of September 10, 1997, between the
Company and The Bank of New York, as Trustee.(f)
*4.2.3 Second Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(c)
*4.2.4 Third Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.(d)
*4.3.1 Indenture, dated as of March 31, 1998, between the Company and The
Bank of New York, as Trustee, including form of Notes.(g)
*4.3.2 Supplemental Indenture, dated as of July 24, 1998, between the
Company and The Bank of New York, as Trustee.(g)
*4.3.3 Second Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(c)
*4.3.4 Third Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.(d)
*4.4.1 Indenture, dated as of March 29, 1999, between the Company and The
Bank of New York, as Trustee, including form of Notes.(h)
*4.4.2 First Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(c)
*4.4.3 Second Supplemental Indenture, dated as of April 26, 2004, between
the Company and The Bank of New York, as Trustee.(d)
*4.5.1 Indenture, dated as of March 29, 1999, between the Company and The
Bank of New York, as Trustee, including form of Notes.(h)
*4.5.2 First Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(c)
*4.5.3 Second Supplemental Indenture, dated as of April 26, 2004, between
the Company and The Bank of New York, as Trustee.(d)
+4.6 Indenture, dated as of June 2, 2004, between Power Contract Financing
III, LLC, and Wilmington Trust Company, as Trustee, Accounts Agent,
Paying Agent and Registrar, including form of Notes.
+31.1 Certification of the Chairman, President and Chief Executive Officer
Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
-79-
Exhibit
Number Description
- ------- ---------------------------------------------------------------------
+31.2 Certification of the Executive Vice President and Chief Financial
Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934, as Adopted Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
+32.1 Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
- ----------
+ Filed herewith.
* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2001, filed with the SEC on March 29,
2002.
(b) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-06259) filed with the SEC on June 19,
1996.
(c) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2000, filed with the SEC on March 15,
2001.
(d) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated March 31, 2004, filed with the SEC on May 10, 2004.
(e) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.
(f) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-41261) filed with the SEC on November 28,
1997.
(g) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-61047) filed with the SEC on August 10,
1998.
(h) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3/A (Registration No. 333-72583) filed with the SEC on March 8,
1999.
(b) Reports on Form 8-K
The registrant filed the following reports on Form 8-K during the quarter
ended June 30, 2004:
Date of Report Date Filed Item Reported
-------------------- ------------------ -------------
April 15, 2004 April 19, 2004 5
April 26, 2004 April 28, 2004 5
May 6, 2004 May 12, 2004 12
May 26, 2004 May 27, 2004 5
June 3, 2004 June 9, 2004 5
June 14, 2004 June 15, 2004 5
June 29, 2004 June 29, 2004 5
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SIGNATURES
Pursuant to the requirements of the Securities 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/ ROBERT D. KELLY
-------------------------------------
Robert D. Kelly
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: August 9, 2004
By: /s/ CHARLES B. CLARK, JR.
-------------------------------------
Charles B. Clark, Jr.
Senior Vice President and Corporate
Controller (Principal Accounting Officer)
Date: August 9, 2004
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The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
Exhibit
Number Description
- ------- ---------------------------------------------------------------------
+3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation, as amended through June 2, 2004.
*3.2 Amended and Restated By-laws of Calpine Corporation.(a)
*4.1.1 Indenture, dated as of May 16, 1996, between the Company and U.S.
Bank (as successor trustee to Fleet National Bank), as Trustee,
including form of Notes.(b)
*4.1.2 First Supplemental Indenture, dated as of August 1, 2000, between the
Company and U.S. Bank National Association (as successor trustee to
Fleet National Bank), as Trustee.(c)
*4.1.3 Second Supplemental Indenture, dated as of April 26, 2004, between
the Company and U.S. Bank National Association (as successor trustee
to Fleet National Bank), as Trustee.(d)
*4.2.1 Indenture, dated as of July 8, 1997, between the Company and The Bank
of New York, as Trustee, including form of Notes.(e)
*4.2.2 Supplemental Indenture, dated as of September 10, 1997, between the
Company and The Bank of New York, as Trustee.(f)
*4.2.3 Second Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(c)
*4.2.4 Third Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.(d)
*4.3.1 Indenture, dated as of March 31, 1998, between the Company and The
Bank of New York, as Trustee, including form of Notes.(g)
*4.3.2 Supplemental Indenture, dated as of July 24, 1998, between the
Company and The Bank of New York, as Trustee.(g)
*4.3.3 Second Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(c)
*4.3.4 Third Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.(d)
*4.4.1 Indenture, dated as of March 29, 1999, between the Company and The
Bank of New York, as Trustee, including form of Notes.(h)
*4.4.2 First Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(c)
*4.4.3 Second Supplemental Indenture, dated as of April 26, 2004, between
the Company and The Bank of New York, as Trustee.(d)
*4.5.1 Indenture, dated as of March 29, 1999, between the Company and The
Bank of New York, as Trustee, including form of Notes.(h)
*4.5.2 First Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(c)
*4.5.3 Second Supplemental Indenture, dated as of April 26, 2004, between
the Company and The Bank of New York, as Trustee.(d)
+4.6 Indenture, dated as of June 2, 2004, between Power Contract Financing
III, LLC, and Wilmington Trust Company, as Trustee, Accounts Agent,
Paying Agent and Registrar, including form of Notes.
+31.1 Certification of the Chairman, President and Chief Executive Officer
Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
+31.2 Certification of the Executive Vice President and Chief Financial
Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934, as Adopted Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
+32.1 Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
- ----------
+ Filed herewith.
* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2001, filed with the SEC on March 29,
2002.
(b) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-06259) filed with the SEC on June 19,
1996.
(c) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2000, filed with the SEC on March 15,
2001.
(d) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated March 31, 2004, filed with the SEC on May 10, 2004.
(e) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.
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(f) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-41261) filed with the SEC on November 28,
1997.
(g) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-61047) filed with the SEC on August 10,
1998.
(h) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3/A (Registration No. 333-72583) filed with the SEC on March 8,
1999.
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