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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 September 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:
534,306,554 shares of Common Stock, par value $.001 per share, outstanding
on November 5, 2004.
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CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2004
INDEX
Page No.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Condensed Balance Sheets September 30, 2004 and December 31, 2003.............. 3
Consolidated Condensed Statements of Operations for the Three and Nine Months Ended
September 30, 2004 and 2003............................................................... 5
Consolidated Condensed Statements of Cash Flows for the Nine Months Ended
September 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.......... 41
Item 3. Quantitative and Qualitative Disclosures About Market Risk..................................... 80
Item 4. Controls and Procedures........................................................................ 80
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.............................................................................. 81
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.................................... 86
Item 6. Exhibits....................................................................................... 87
Signatures................................................................................................. 89
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
September 30, 2004 and December 31, 2003
(in thousands, except share and per share amounts)
September 30, December 31,
2004 2003
-------------- -------------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents........................................................................ $ 1,487,822 $ 991,806
Accounts receivable, net......................................................................... 1,090,073 988,947
Margin deposits and other prepaid expense........................................................ 371,679 385,348
Inventories...................................................................................... 155,901 137,740
Restricted cash.................................................................................. 935,990 383,788
Current derivative assets........................................................................ 416,930 496,967
Current assets held for sale..................................................................... -- 2,565
Other current assets............................................................................. 270,621 89,593
-------------- --------------
Total current assets........................................................................... 4,729,016 3,476,754
-------------- --------------
Restricted cash, net of current portion............................................................ 150,020 575,027
Notes receivable, net of current portion........................................................... 223,590 213,629
Project development costs.......................................................................... 144,625 139,953
Investments in power projects and oil and gas properties........................................... 392,611 444,150
Deferred financing costs........................................................................... 434,986 400,732
Prepaid lease, net of current portion.............................................................. 394,778 414,058
Property, plant and equipment, net................................................................. 20,620,243 19,478,650
Goodwill, net...................................................................................... 45,160 45,160
Other intangible assets, net....................................................................... 83,922 89,924
Long-term derivative assets........................................................................ 587,000 673,979
Long-term assets held for sale..................................................................... -- 743,149
Other assets....................................................................................... 624,968 608,767
-------------- --------------
Total assets.................................................................................. $ 28,430,919 $ 27,303,932
============== ==============
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable................................................................................. $ 1,099,430 $ 938,644
Accrued payroll and related expense.............................................................. 78,915 96,693
Accrued interest payable......................................................................... 365,850 321,176
Income taxes payable............................................................................. 9,224 18,026
Notes payable and borrowings under lines of credit, current portion.............................. 210,603 254,292
Notes payable to Calpine Capital Trusts, current portion......................................... 636,000 --
Preferred interests, current portion............................................................. 9,040 11,220
Capital lease obligation, current portion........................................................ 7,923 4,008
CCFC I financing, current portion................................................................ 3,208 3,208
Construction/project financing, current portion.................................................. 62,839 61,900
Convertible Senior Notes Due 2006, current portion............................................... 72,126 --
Senior notes and term loans, current portion..................................................... 198,409 14,500
Current derivative liabilities................................................................... 524,025 456,688
Current liabilities held for sale................................................................ -- 221
Other current liabilities........................................................................ 485,805 334,827
-------------- --------------
Total current liabilities...................................................................... 3,763,397 2,515,403
-------------- --------------
Notes payable and borrowings under lines of credit, net of current portion......................... 781,017 873,572
Notes payable to Calpine Capital Trusts, net of current portion.................................... 517,500 1,153,500
Preferred interests, net of current portion........................................................ 138,068 232,412
Capital lease obligation, net of current portion................................................... 283,442 193,741
CCFC I financing, net of current portion........................................................... 783,139 785,781
CalGen/CCFC II financing........................................................................... 2,431,370 2,200,358
Construction/project financing, net of current portion............................................. 1,697,540 1,209,505
Convertible Senior Notes Due 2006, net of current portion.......................................... -- 660,059
Convertible Notes Due 2014......................................................................... 617,504 --
Convertible Senior Notes Due 2023.................................................................. 633,775 650,000
Senior notes and term loans, net of current portion................................................ 9,339,577 9,369,253
Deferred income taxes, net......................................................................... 1,346,860 1,310,335
Deferred lease incentive........................................................................... -- 50,228
Deferred revenue................................................................................... 112,087 116,001
Long-term derivative liabilities................................................................... 641,280 692,088
Long-term liabilities held for sale................................................................ -- 17,828
Other liabilities.................................................................................. 333,876 241,723
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Total liabilities............................................................................. 23,420,432 22,271,787
-------------- --------------
Minority interests................................................................................. 371,946 410,892
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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 September 30, 2004; issued and outstanding 534,092,147 shares in
2004 and 415,010,125 shares in 2003............................................................ 534 415
Additional paid-in capital....................................................................... 3,137,913 2,995,735
Additional paid-in capital, loaned shares........................................................ 258,100 --
Additional paid-in capital, returnable shares.................................................... (258,100) --
Retained earnings................................................................................ 1,483,638 1,568,509
Accumulated other comprehensive income........................................................... 16,456 56,594
-------------- --------------
Total stockholders' equity.................................................................. $ 4,638,541 $ 4,621,253
-------------- --------------
Total liabilities and stockholders' equity.................................................. $ 28,430,919 $ 27,303,932
============== ==============
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three and Nine Months Ended September 30, 2004 and 2003
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ----------------------------
2004 2003 2004 2003
------------- ------------- ------------- -------------
(In thousands, except
per share amounts)
(Unaudited)
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue....................................... $ 1,671,147 $ 1,416,866 $ 4,230,004 $ 3,563,193
Transmission sales revenue.......................................... 4,427 3,952 14,152 13,239
Sales of purchased power for hedging and optimization............... 430,576 843,013 1,307,256 2,269,102
------------- ------------- ------------- -------------
Total electric generation and marketing revenue.................... 2,106,150 2,263,831 5,551,412 5,845,534
Oil and gas production and marketing revenue
Oil and gas sales................................................... 17,687 16,578 47,472 45,394
Sales of purchased gas for hedging and optimization................. 423,733 305,706 1,258,441 961,652
------------- ------------- ------------- -------------
Total oil and gas production and marketing revenue................. 441,420 322,284 1,305,913 1,007,046
Mark-to-market activities, net........................................ (5,106) (11,023) (15,192) 11,259
Other revenue......................................................... 14,736 81,496 51,573 97,596
------------- ------------- ------------- -------------
Total revenue.................................................... 2,557,200 2,656,588 6,893,706 6,961,435
------------- ------------- ------------- -------------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense............................................. 176,333 174,545 575,830 496,119
Transmission purchase expense....................................... 30,803 17,335 61,880 37,491
Royalty expense..................................................... 8,488 7,022 21,321 18,840
Purchased power expense for hedging and optimization................ 351,151 835,892 1,171,260 2,254,560
------------- ------------- ------------- -------------
Total electric generation and marketing expense.................... 566,775 1,034,794 1,830,291 2,807,010
Oil and gas operating and marketing expense
Oil and gas operating expense....................................... 14,719 15,263 42,864 53,642
Purchased gas expense for hedging and optimization.................. 429,373 293,241 1,243,781 941,312
------------- ------------- ------------- -------------
Total oil and gas operating and marketing expense.................. 444,092 308,504 1,286,645 994,954
Fuel expense.......................................................... 1,097,650 806,598 2,783,570 2,035,285
Depreciation, depletion and amortization expense...................... 149,288 131,001 421,050 373,128
Operating lease expense............................................... 25,805 28,439 80,567 84,298
Other cost of revenue................................................. 19,187 8,380 68,177 20,501
------------- ------------- ------------- -------------
Total cost of revenue............................................ 2,302,797 2,317,716 6,470,300 6,315,176
------------- ------------- ------------- -------------
Gross profit................................................... 254,403 338,872 423,406 646,259
Loss (income) from unconsolidated investments in power projects and oil
and gas properties.................................................... 10,859 (4,110) 11,663 (68,584)
Equipment cancellation and impairment cost.............................. 7,820 632 10,187 19,940
Long-term service agreement cancellation charge......................... 7,580 -- 7,580 --
Project development expense............................................. 3,367 2,979 15,114 14,137
Research and development expense........................................ 3,982 2,849 12,921 7,709
Sales, general and administrative expense............................... 58,377 49,426 170,990 142,841
------------- ------------- ------------- -------------
Income from operations................................................ 162,418 287,096 194,951 530,216
Interest expense........................................................ 293,639 198,686 815,357 483,238
Distributions on trust preferred securities............................. -- 15,297 -- 46,610
Interest income......................................................... (17,185) (10,742) (39,166) (27,780)
Minority interest expense............................................... 9,990 2,569 23,149 10,182
Income from repurchase of various issuances of debt..................... (167,154) (207,238) (170,548) (214,001)
Other expense (income).................................................. 23,320 9,513 (177,088) 64,570
------------- ------------- ------------- -------------
Income (loss) before provision (benefit) for income taxes............. 19,808 279,011 (256,753) 167,397
Provision (benefit) for income taxes.................................... 67,340 41,310 (81,955) 11,076
------------- ------------- ------------- -------------
Income (loss) before discontinued operations and cumulative effect of
a change in accounting principle.................................... (47,532) 237,701 (174,798) 156,321
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- ----------------------------
2004 2003 2004 2003
------------- ------------- ------------- -------------
(In thousands, except
per share amounts)
(Unaudited)
Discontinued operations, net of tax provision (benefit) of $140,724,
$(183), $155,790, and $3,123.......................................... 62,551 81 89,927 5,550
Cumulative effect of a change in accounting principle, net of tax
provision of $--, $--, $--and $450.................................... -- -- -- 529
------------- ------------- ------------- -------------
Net income (loss)............................................... $ 15,019 $ 237,782 $ (84,871) $ 162,400
============= ============= ============= =============
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding................... 444,380 388,161 425,682 383,447
Income (loss) before discontinued operations and cumulative effect
of a change in accounting principle.................................. $ (0.11) $ 0.61 $ (0.41) $ 0.41
Discontinued operations, net of tax................................... $ 0.14 $ -- $ 0.21 $ 0.01
Cumulative affect of a change in accounting principle, net of tax..... $ -- $ -- $ -- $ --
------------- ------------- ------------- -------------
Net income (loss)............................................... $ 0.03 $ 0.61 $ (0.20) $ 0.42
============= ============= ============= =============
Diluted earnings per common share:
Weighted average shares of common stock outstanding before
dilutive effect of certain convertible securities.................... 444,380 394,950 425,682 388,622
Income (loss) before dilutive effect of certain convertible
securities, discontinued operations and cumulative effect of a change
in accounting principle.............................................. $ (0.11) $ 0.60 $ (0.41) $ 0.40
Dilutive effect of certain convertible securities..................... -- (0.09) -- --
------------- ------------- ------------- -------------
Income (loss) before discontinued operations and cumulative effect of
a change in accounting principle..................................... (0.11) 0.51 (0.41) 0.40
Discontinued operations, net of tax................................... 0.14 -- 0.21 0.01
Cumulative effect of a change in accounting principle, net of tax..... -- -- -- --
------------- ------------- ------------- -------------
Net income (loss)............................................... $ 0.03 $ 0.51 $ (0.20) $ 0.41
============= ============= ============= =============
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2004 and 2003
(in thousands)
(unaudited)
Nine Months Ended
September 30,
-------------------------------
2004 2003
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Cash flows from operating activities:
Net income (loss)................................................................................ $ (84,871) $ 162,400
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization (1).................................................. 598,855 489,431
Deferred income taxes, net.................................................................... (80,065) 204,900
(Gain) loss on sale of assets and development cost write-offs, net............................ (193,509) 6,606
Gain on repurchase of debt.................................................................... (170,548) (192,296)
Equipment cancellation and impairment cost.................................................... 10,187 19,940
Stock compensation expense.................................................................... 15,190 12,028
Foreign exchange losses....................................................................... 7,521 36,234
Mark-to-market loss and other non-cash derivative activity.................................... 40,782 2,535
Loss (income) from unconsolidated investments in power projects and oil and gas properties.... 11,663 (68,584)
Distributions from unconsolidated investments in power projects............................... 22,263 125,679
Other......................................................................................... 64,386 10,505
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable........................................................................... (104,787) (161,262)
Other current assets.......................................................................... (1,202) (150,573)
Other assets.................................................................................. (66,224) (142,530)
Accounts payable and accrued expense.......................................................... 218,862 (197,586)
Other liabilities............................................................................. (58,633) 13,905
-------------- -------------
Net cash provided by operating activities................................................... 229,870 171,332
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Cash flows from investing activities:
Purchases of property, plant and equipment....................................................... (1,184,352) (1,523,643)
Disposals of property, plant and equipment....................................................... 1,151,246 15,255
Acquisitions, net of cash acquired............................................................... (187,786) (6,818)
Advances to joint ventures....................................................................... (8,833) (51,945)
Project development costs........................................................................ (23,605) (30,184)
Sale of collateral securities.................................................................... 93,963 --
Repurchase of High Tides......................................................................... (111,550) --
Increase in restricted cash...................................................................... (124,153) (258,255)
Decrease (increase) in notes receivable.......................................................... 9,979 (13,708)
Other............................................................................................ 3,157 32,717
-------------- -------------
Net cash used in investing activities....................................................... (381,934) (1,836,581)
-------------- -------------
Cash flows from financing activities:
Borrowings from notes payable and borrowings under lines of credit............................... 97,191 1,323,618
Repayments of notes payable and borrowings under lines of credit................................. (328,943) (1,750,866)
Borrowings from project financing................................................................ 3,477,854 1,369,900
Repayments of project financing.................................................................. (2,942,272) (1,395,788)
Repayments and repurchases of Senior Notes....................................................... (630,275) (906,308)
Repurchase of 4% Convertible Senior Notes........................................................ (586,926) (101,887)
Proceeds from issuance of Convertible Senior Notes............................................... 867,504 --
Proceeds from issuance of Senior Notes........................................................... 878,815 3,500,000
Proceeds from income trust offering.............................................................. -- 126,462
Proceeds from issuance of common stock........................................................... 95 8,184
Proceeds from King City financing transaction.................................................... -- 82,000
Financing costs.................................................................................. (175,802) (244,069)
Other............................................................................................ (23,538) 35,243
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Net cash provided by financing activities................................................... 633,703 2,046,489
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Effect of exchange rate changes on cash and cash equivalents....................................... 14,377 8,946
Net increase in cash and cash equivalents.......................................................... 496,016 390,186
Cash and cash equivalents, beginning of period..................................................... 991,806 579,486
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Cash and cash equivalents, end of period........................................................... $ 1,487,822 $ 969,672
============== =============
Cash paid during the period for:
Interest, net of amounts capitalized............................................................. $ 674,875 $ 322,051
Income taxes..................................................................................... $ 21,863 $ 12,481
- ------------
<FN>
(1) Includes depreciation and amortization that is charged to cost of revenue,
discontinued operations and also included within sales, general and
administrative expense and to interest expense in the Consolidated
Condensed Statements of Operations.
Schedule of noncash investing and financing activities:
2004 issuance of 24.3 million shares of common stock in exchange for $40.0
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 for an initial
asset balance of $114.9 million.
2004 issuance of 89 million shares of Calpine common stock pursuant to a
Share Lending Agreement. See Note 6 for more information regarding the 89
million shares issued.
2004 exchange of a $177.0 million note for $266.2 million of our 4.75%
Contingent Convertible Senior Notes Due 2023.
</FN>
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
September 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 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/A. 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 reclassifications from plant operating expense to transmission
purchase expense.
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 reserve quantities used to calculate
depletion, depreciation and impairment of oil and gas property and equipment.
Effective Tax Rate -- For the three months ended September 30, 2004 and
2003, the Company's effective rate was 340% and 15%, respectively. For the nine
months ended September 30, 2004 and 2003, the effective rate was (32)% and 7%,
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. Also, see Note 15 concerning the
impact of tax legislation passed October 22, 2004.
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.
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").
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):
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- ------------------------
2004 2003 2004 2003
----------- ----------- ----------- -----------
Sales of purchased power for hedging and optimization...... $ 563,293 $ -- $ 1,255,760 $ --
----------- ----- ----------- -----
Purchased power expense for hedging and optimization....... 563,293 -- 1,255,760 --
----------- ----- ----------- -----
$ -- $ -- $ -- $ --
=========== ===== =========== =====
Preferred Interests -- As required in SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,"
("SFAS No. 150") 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.
New Accounting Pronouncements
Stock-Based Compensation
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 nine months ended
September 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 Nine Months Ended
September 30, September 30,
------------------------ ------------------------
2004 2003 2004 2003
----------- ----------- ----------- -----------
Net income (loss)
As reported......................................................... $ 15,019 $ 237,782 $ (84,871) $ 162,400
Pro Forma........................................................... 13,996 234,353 (88,818) 148,780
Income (loss) per share data:
Basic loss per share
As reported....................................................... $ 0.03 $ 0.61 $ (0.20) $ 0.42
Pro Forma......................................................... 0.03 0.60 (0.21) 0.39
Diluted earnings per share
As reported....................................................... $ 0.03 $ 0.51 $ (0.20) $ 0.41
Pro Forma......................................................... 0.03 0.50 (0.21) 0.38
Stock-based compensation cost, net of tax, included in income
(loss), as reported................................................. $ 3,308 $ 3,068 $ 9,388 $ 10,699
Stock-based compensation cost, net of tax, included in income
(loss), pro forma................................................... 4,331 6,497 13,335 24,319
The range of fair values of the Company's stock options granted for the
three months ended September 30, 2004 and 2003, respectively, was as follows,
based on varying historical stock option exercise patterns by different levels
of Calpine employees: $2.39 in 2004, $3.58-3.75 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 84.24% and
101.49%-106.91% for the three months ended September 30, 2004 and 2003,
respectively; risk-free interest rates of 3.37% and 1.42-1.60% for the three
months ended September 30, 2004 and 2003, respectively; and expected option
terms of 4 years and 1.5 years for the three months ended September 30, 2004 and
2003, respectively.
The range of fair values of the Company's stock options granted for the
nine months ended September 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, $1.60-$5.16 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 nine months ended
September 30, 2004 and 2003, respectively; risk-free interest rates of
2.35%-4.54% and 1.39%-4.04% for the nine months ended September 30, 2004 and
2003, respectively; and expected option terms of 3-9 1/2 years and 1.5-9.5 years
for the nine months ended September 30, 2004 and 2003, respectively.
FIN 46 and FIN 46-R
In January 2003 the 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 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 the 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 the Company's wholly 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 the Company's wholly owned
subsidiaries. As part of the Company's quantitative assessment, a fair value
methodology was used to determine whether the Company or the power purchaser
absorbs the majority of the subsidiary's variability. The Company qualitatively
determined that power sales or tolling agreements with a term for less than
one-third of the facility's remaining useful life or 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.
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. 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
six VIE investments were in SPEs: Calpine Northbrook Energy Marketing, LLC
("CNEM"), Power Contract Financing, L.L.C. ("PCF"), Power Contract Financing LLC
III ("PCF III") and Calpine Capital Trust I ("Trust I"), Calpine Capital Trust
II ("Trust II") and Calpine Capital Trust III ("Trust III" and together with
Trust I and Trust II, the "Trusts") 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 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, 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 the Trusts 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
EITF Issue No. 88-18, "Sales of Future Revenue" ("EITF Issue No. 88-18") or
Statement of Financial Accounting Standard No. 140, "Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities" ("SFAS No.
140"), as appropriate. When EITF Issue No. 88-18 and SFAS No. 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 Issue No. 88-18 or
SFAS No. 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 EITF
Issue No. 88-18 or SFAS No. 140:
FIN 46-R Sale or
Treatment Financing
------------- ----------
CNEM................................................ Consolidate N/A
PCF................................................. Deconsolidate Financing
PCF III............................................. Deconsolidate Financing
Trust I, Trust II and Trust III.................... Deconsolidate Financing
EITF 04-7
An integral part of applying FIN 46-R is determining which economic
interests are variable interests. In order for an interest to be considered a
variable interest, it must "absorb variability" of changes in the fair value of
the VIE's underlying net assets. Questions have arisen regarding (a) how to
determine whether an interest absorbs variability , and (b) whether the nature
of how a long position is created, either synthetically through derivative
transactions or through cash transactions, should affect the assessment of
whether an interest is a variable interest. EITF Issue No. 04-7 : "Determining
Whether an Interest Is a Variable Interest in a Potential Variable Interest
Entity" ("EITF Issue No. 04-7") is still in the discussion phase, but will
eventually provide a model to assist in determining whether an economic interest
in a VIE is a variable interest. The Task Force's discussions on this Issue have
centered around whether the variability should be based on whether (a) the
interest absorbs fair value variability, (b) the interest absorbs cash flow
variability, or (c) the interest absorbs both fair value and cash flow
variability. The final conclusions reached on this issue may impact the
Company's methodology used in making quantitative assessments of the variability
of: the Company's joint venture investments: wholly owned subsidiaries that have
issued preferred interests to third parties; wholly owned subsidiaries that have
entered into operating leases of power plants that contain a fixed price
purchase option; wholly owned subsidiaries that have entered into longer term
power sales agreements with third parties; and the Company's investments in
SPEs. However, until the EITF reaches a final consensus, the effects of this
issue on the Company's financial statements is indeterminable.
EITF 04-8
On September 30, 2004, the EITF reached a final consensus on EITF Issue No.
04-8 ("EITF Issue No. 04-8"): "The Effect of Contingently Convertible Debt on
Diluted Earnings per Share." The guidance in EITF Issue No. 04-8 is effective
for periods ending after December 15, 2004, and must be applied by retroactively
restating previously reported earnings per shares. The consensus requires
companies that have issued contingently convertible instruments with a market
price trigger to include the effects of the conversion in diluted earnings per
share, regardless of whether the price trigger had been met. Prior to this
consensus, contingently convertible instruments were not included in diluted
earnings per share if the price trigger had not been met. Typically, the
affected instruments are convertible into common stock of the issuer after the
issuer's common stock price has exceeded a predetermined threshold for a
specified time period. Calpine's $634 million outstanding at September 30, 2004,
of 4.75% Contingent Convertible Senior Notes Due 2023 ("2023 Convertible Senior
Notes") and $736 million aggregate principal amount at maturity of Contingent
Convertible Notes Due 2014 ("2014 Convertible Notes") will be affected by the
new guidance. This new guidance will accelerate the point at which the 2023
Convertible Senior Notes and 2014 Convertible Notes would potentially impact its
diluted earnings per share, but once the trigger price is exceeded, there would
be no additional dilution.
SFAS No. 128-R
FASB is expected to modify Statement of Financial Accounting Standards No.
128: Earnings Per Share ("SFAS No. 128") to make it consistent with
International Accounting Standard No. 33, Earnings Per Share, so that earnings
per share computations will be comparable on a global basis. The effective date
is anticipated to coincide with the effective date of EITF Issue No. 04-8. The
proposed changes will affect the application of the treasury stock method and
contingently issuable (based on conditions other than market price) share
guidance for computing year-to-date diluted earnings per share. In addition to
modifying the year-to-date calculation mechanics, the proposed revision to SFAS
No. 128 would eliminate a company's ability to overcome the presumption of share
settlement for those instruments or contracts that can be settled, at the issuer
or holder's option, in cash or shares. Under the revised guidance, the FASB has
indicated that any possibility of share settlement other than in an event of
bankruptcy will require an assumption of share settlement when calculating
diluted earnings per share. The Company's 2023 Convertible Senior Notes and 2014
Convertible Notes contain provisions that would require share settlement in the
event of conversion, during certain limited events of default, including
bankruptcy. Additionally, the 2023 Convertible Senior Notes include a provision
allowing the Company to meet a put with either cash or shares of stock. The
revised guidance is expected to increase the potential dilution to the Company's
earnings per share, particularly when the price of the Company's common stock is
low, since the more dilutive of the calculations would be used considering both:
(i) normal conversion assuming a combination of cash and a variable number of
shares; and (ii) conversion during certain limited events of default assuming
100% shares at the fixed conversion rate.
EITF 03-13
At the September 29, 2004, EITF meeting, the EITF reached a tentative
conclusion on Issue No. 03-13: Applying the Conditions in Paragraph 42 of FASB
Statement No. 144 in Determining Whether to Report Discontinued Operations. The
Issue provides a model to assist in evaluating (a) which cash flows should be
considered in the determination of whether cash flows of the disposal component
have been or will be eliminated from the ongoing operations of the entity and
(b) the types of continuing involvement that constitute significant continuing
involvement in the operations of the disposal component. FASB is expected to
ratify the consensus at its November 2004 meeting with prospective application
to transactions entered into after January 1, 2005. The Company considered the
model outlined in EITF Issue No. 03-13 in its evaluation of the sale of the
Canadian and Rockies disposal groups (see Note 8 for more information) and does
not expect the new guidance to change the conclusions reached under the existing
discontinued operations guidance in SFAS No. 144.
3. Available-for-Sale Debt Securities
During the quarter, the Company exchanged 4.2 million shares of Calpine
common stock in privately negotiated transactions for $20.0 million par value of
HIGH TIDES I and repurchased $115.0 million par value of HIGH TIDES III. Due to
the deconsolidation of the Trusts upon the adoption of FIN 46-R, the repurchased
HIGH TIDES preferred securities are reflected as assets on the balance sheet.
The repurchased HIGH TIDES I are reflected on the balance sheet in Other
Current Assets along with previously repurchased HIGH TIDES I and II. See Note
15 for a discussion of the redemption of HIGH TIDES I and II subsequent to
September 30, 2004. 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 No. 115"). Therefore, the
following HIGH TIDES I and II were recorded at fair market value at September
30, 2004, with the difference from their repurchase price recorded in Other
Comprehensive Income (in thousands):
September 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................................. $ 75,212 $2,288 $ -- $ 77,500
HIGH TIDES II................................ 71,341 3,659 -- 75,000
----------- ------ ---------- -----------
Debt securities............................ $ 146,553 $5,947 $ -- $ 152,500
=========== ====== ========== ===========
The repurchased HIGH TIDES III are reflected on the balance sheet in Other
Assets. The following HIGH TIDES III were recorded at fair market value in Other
Assets at September 30, 2004, with the difference from their repurchase price
recorded in Other Comprehensive Income (in thousands):
September 30, 2004
---------------------------------------------
Gross Gross
Unrealized Unrealized
Gains in Other Losses in Other
Repurchase Comprehensive Comprehensive Fair
Price Income/(Loss) Income/(Loss) Value
----------- -------------- --------------- -----------
HIGH TIDES III............................... $ 110,592 $ -- $ (192) $ 110,400
----------- ------ --------- -----------
Debt securities............................ $ 110,592 $ -- $ (192) $ 110,400
=========== ====== ========= ===========
4. Property, Plant and Equipment, Net and Capitalized Interest
As of September 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):
September 30, December 31,
2004 2003
-------------- -------------
Buildings, machinery, and equipment............ $ 16,102,657 $ 13,226,310
Oil and gas properties, including pipelines.... 1,077,093 1,088,035
Geothermal properties.......................... 471,533 460,602
Other.......................................... 552,982 234,759
------------- -------------
18,204,265 15,009,706
Less: accumulated depreciation and depletion... (1,790,363) (1,388,225)
------------- -------------
16,413,902 13,621,481
Land........................................... 98,922 95,037
Construction in progress....................... 4,107,419 5,762,132
------------- -------------
Property, plant and equipment, net.......... $ 20,620,243 $ 19,478,650
============= =============
Capital Spending -- Construction and Development
Construction and Development costs in process consisted of the following at
September 30, 2004 (in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP CIP Costs Equipment
-------- ---------- ----------- ----------- ----------
Projects in active construction........... 10 $2,935,248 $1,057,034 $ -- $ --
Projects in advanced development.......... 11 671,594 529,475 122,769 --
Projects in suspended development......... 6 455,013 195,818 12,904 --
Projects in early development............. 2 -- -- 8,952 --
Other capital projects.................... NA 45,564 -- -- --
Unassigned................................ NA -- -- -- 66,133
---------- ---------- ---------- ----------
Total construction and development costs $4,107,419 $1,782,327 $ 144,625 $ 66,133
========== ========== ========== ==========
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 10 projects in active construction
are estimated to come on line from February 2005 to November 2007. These
projects will bring on line approximately 4,634 MW of base load capacity (5,244
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. One additional project, Goldendale, totaling 237 MW of base load
capacity (271 MW with peaking capacity) that was in active construction at the
beginning of the quarter went on line during the quarter. At September 30, 2004,
the estimated funding requirements to complete these 10 projects, net of
expected project financing proceeds, is approximately $0.4 billion.
Projects in Advanced Development -- There are 11 projects in advanced
development. These projects will bring on line approximately 5,585 MW of base
load capacity (6,651 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. At
September 30, 2004, the estimated cost to complete the 11 projects in advanced
development is approximately $3.7 billion. The Company's current plan is to
commence construction with project financing, once power purchase agreements are
arranged.
Suspended Development Projects -- The Company has ceased capitalization of
additional development costs and interest expense on certain development
projects on which work has been suspended, due to current electric market
conditions. 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 3,458 MW of base load capacity (3,938 MW with peaking
capacity). At September 30, 2004, the estimated cost to complete the six
projects is approximately $2.1 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 September 30, 2004, the Company had made
progress payments on four turbines, one heat recovery steam generator and other
equipment with an aggregate carrying value of $66.1 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 September 30, 2004 and 2003, the total amount
of interest capitalized was $86.8 million and $98.7 million, respectively,
including $9.4 million and $13.0 million, respectively, of interest incurred on
funds borrowed for specific construction projects and $77.4 million and $85.7
million, respectively, of interest incurred on general corporate funds used for
construction. For the nine months ended September 30, 2004 and 2003, the total
amount of interest capitalized was $297.4 million and $333.7 million,
respectively, including $43.3 million and $51.4 million, respectively, of
interest incurred on funds borrowed for specific construction projects and
$254.1 million and $282.3 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 nine months ended September
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.
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 projects including those under construction
and development 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 September 30, 2004, is limited to the book value
of its investment of approximately $216.9 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"), now
called Calpine Cogeneration Corporation, 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 September 30, 2004, is limited
to the book value of its investment of approximately $48.7 million.
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 September 30, 2004,
is limited to the book value of its investment of approximately $35.3 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 September 30, 2004, was limited
to $39.0 million, which represents the book value of its investment of
approximately $15.9 million and a notes receivable, including accrued but unpaid
interest, from AELLC with a carrying value of $23.1 million as described below.
See Notes 12 and 15 for a description and an update on litigation involving
AELLC.
On September 2, 2004, the Company completed the sale of its equity
investment in the Calpine Natural Gas Trust ("CNGT"). In accordance with SFAS
No. 144, "Accounting For the Impairment or Disposal of Long-Lived Assets,"
("SFAS No. 144") the Company's 25 percent equity method investment in the
CNGTwas considered part of the larger disposal group and therefore evaluated and
accounted for as a discontinued operation. Accordingly, the following tables for
investment balance as well as income (loss) from investments do not include the
CNGT. However, tables for distributions from investments and related party
transactions with equity method affiliates include CNGT through the date of
sale, September 2, 2004. See Note 8 for more information on the sale of the
Canadian natural gas reserves and petroleum assets.
The following investments are accounted for under the equity method (in
thousands):
Ownership Investment Balance at
Interest as ----------------------------
of
September 30, September 30, December 31,
2004 2004 2003
------------- ------------- ------------
Acadia Energy Center............................................... 50.0% $ 216,852 $ 221,038
Valladolid III IPP................................................. 45.0% 74,236 67,320
Grays Ferry Power Plant (1)........................................ 50.0% 48,659 53,272
Whitby Cogeneration (2)............................................ 15.0% 35,349 31,033
Androscoggin Power Plant........................................... 32.3% 15,863 11,823
Aries Power Plant (3).............................................. 100.0% -- 58,205
Other.............................................................. -- 1,652 1,459
----------- -----------
Total investments in power projects and oil and gas properties... $ 392,611 $ 444,150
=========== ===========
- ------------
<FN>
(1) On March 23, 2004, the Company completed the acquisition of the remaining
20% interest in Cogen America. 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 Calpine
Power Limited Partnership ("CPLP") through a loan from CPLP 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
September 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 September
30, 2004, third-party investee debt is approximately $130.1 million. Based on
the Company's pro rata ownership share of each of the investments, the Company's
share would be approximately $45.7 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 has construction debt of $58.6 million outstanding as of
September 30, 2004. The debt is non-recourse to the Company (the "AELLC
Non-Recourse Financing"). On September 30, 2004, and December 31, 2003, the
Company's investment balance was $15.9 million and $11.8 million, respectively,
and the carrying value of its notes receivable, including accrued but unpaid
interest, from AELLC was $23.1 million and $14.7 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, because the lending syndication had declined to extend
the date for the conversion of the construction loan to a term loan by a certain
date. AELLC has disputed the purported defaults. Also, the steam host for the
AELLC project, International Paper Company ("IP"), filed a complaint against
AELLC in October 2000, which resulted in a jury verdict for $41 million in favor
of IP on November 3, 2004. See Notes 12 and 15 for a further discussion of the
IP litigation. The litigation with IP 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 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 Nine Months Ended September 30,
---------------------------------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
Acadia Energy Center.......................................... $ 9,490 $ 70,990 $ 14,438 $ 124,613
Aries Power Plant............................................. (4,265) (539) -- --
Grays Ferry Power Plant....................................... (2,436) (1,864) -- --
Whitby Cogeneration........................................... 870 788 1,515 --
Androscoggin Power Plant...................................... (16,680) (5,409) -- --
Gordonsville Power Plant (1).................................. -- 4,155 -- 1,050
CNGT.......................................................... -- -- 6,127 --
Other......................................................... 518 211 183 16
--------- --------- --------- ----------
Total....................................................... $ (12,503) $ 68,332 $ 22,263 $ 125,679
========= ========= ========= ==========
Interest income on notes receivable from power projects (2) $ 840 $ 252
--------- ---------
Total....................................................... $ (11,663) $ 68,584
========= =========
- ------------
<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) Notes receivable from power projects represented an outstanding loan to the
Company's investment, AELLC, with carrying values of $23.1 million and
$14.7 million, including accrued but unpaid interest, respectively, at
September 30, 2004, and December 31, 2003.
</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.
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 September
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 nine months ended September 30, 2004, and 2003,
reflected in the accompanying Consolidated Condensed Statements of Operations
are summarized as follows (in thousands):
September 30, December 31,
2004 2003
------------- ------------
Accounts receivable.................... $ 55 $ 1,156
Accounts payable....................... 8,056 12,172
Interest receivable.................... 2,261 2,074
Note Receivable, principal amount...... 20,872 13,262
Other receivables...................... 11,137 8,794
2004 2003
--------- ---------
For the Three Months Ended September 30
Cost of Revenue......................................... $ 25,504 $ 21,566
Maintenance fee revenue................................. 40 157
Interest income......................................... 347 138
For the Nine Months Ended September 30
Revenue................................................. $ 699 $ 455
Cost of Revenue......................................... 89,623 52,649
Maintenance fee revenue................................. 254 460
Interest income......................................... 840 252
Gain on sale of assets.................................. 6,240 --
6. Financing
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. 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. See Note 15
for the redemption of HIGH TIDES I and II subsequent to September 30, 2004.
On August 5, 2004, the Company announced that its newly created entity,
Calpine Energy Management, L.P. ("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.
On September 1, 2004, the Company, along with Calpine Natural Gas L.P.,
completed the sale of its Rocky Mountain gas reserves that were primarily
concentrated in two geographic areas: the Colorado Piceance Basin and the New
Mexico San Juan Basin. Together, these assets represent approximately 120
billion cubic feet equivalent ("Bcfe") of proved gas reserves, producing
approximately 16.3 million net cubic feet equivalent ("MMcfed") per day of gas.
Under the terms of the agreement, the Company received cash payments of
approximately $222.8 million, and recorded a pre-tax gain of approximately
$102.9 million. Proceeds derived from this sale were applied as a mandatory
paydown, pursuant to covenants governing asset sales, under the Company's First
Priority Senior Secured Term Loan B Notes Due 2007 and the $300 million Working
Capital Revolver.
On September 2, 2004, the Company completed the sale of its Canadian
natural gas reserves and petroleum assets. These Canadian assets represent
approximately 221 Bcfe of proved reserves, producing approximately 61 MMcfed.
Included in this sale was the Company's 25 percent interest in approximately 80
Bcfe of proved reserves (net of royalties) and 32 MMcfe of production owned by
the Calpine Natural Gas Trust. Under the terms of the agreement, the Company
received cash payments of approximately Cdn$825.0 million, or approximately
US$625 million, less adjustments of Cdn$15.6 million, on the September 2, 2004,
closing date. The Company recorded a pre-tax gain of approximately $100.6
million on the sale of its Canadian assets. A portion of the proceeds derived
from this sale were applied as a mandatory paydown under the Company's First
Priority Senior Secured Term Loan B Notes Due 2007 and the $300 million Working
Capital Revolver, at which date the remaining obligations under these loan
facilities were fully paid down and related letters of credit cash
collateralized.
On September 30, 2004, the Company established a new $255 million Cash
Collateralized Letter of Credit Facility with Bayerische Landesbank, under which
all letters of credit previously issued under the $300 million Working Capital
Revolver and the $200 million Cash Collateralized Letter of Credit Facility will
be transitioned into that new Facility. Upon completion of this transition, all
letters of credit presently collateralized with The Bank of Nova Scotia will be
terminated.
On September 30, 2004, the Company closed on $785 million of 9 5/8%
First-Priority Senior Secured Notes Due 2014 ("9 5/8% Senior Notes"), offered at
99.212% of par. The 9 5/8% Senior Notes are secured, by substantially all of the
assets owned directly by Calpine Corporation, and by the stock of substantially
all of its first-tier subsidiaries. Net proceeds from the 9 5/8% Senior Notes
offering were used to make open-market purchases of the Company's existing
indebtedness and any remaining proceeds will be applied toward further
open-market purchases (or redemption) of existing indebtedness and as otherwise
permitted by the Company's indentures.
On September 30, 2004, the Company closed on $736 million aggregate
principal amount at maturity of Contingent Convertible Notes Due 2014 ("2014
Convertible Notes"), offered at 83.9% of par. The 2014 Convertible Notes will be
convertible into cash and into a variable number of shares of Calpine common
stock based on a conversion value derived from the conversion price of $3.85 per
share. The number of shares to be delivered upon conversion will be determined
by the market price of Calpine common shares at the time of conversion. The
conversion price of $3.85 per share represents a premium of approximately 23%
over The New York Stock Exchange closing price of $3.14 per Calpine common share
on September 27, 2004. The 2014 Convertible Notes will pay interest at a rate of
6%, except that in years three, four and five, in lieu of interest, the original
principal amount of $839 per note will accrete daily beginning September 30,
2006, to the full principal amount of $1,000 per note at September 30, 2009.
Upon conversion of the 2014 Convertible Notes, the Company will deliver the
portion of the conversion value equal to the then current principal amount of
the 2014 Convertible Notes in cash and any additional conversion value in
Calpine common stock.
Net proceeds from the 2014 Convertible Notes offering were used to redeem
the Company's HIGH TIDES I and HIGH TIDES II preferred securities on October 20,
2004, (see Note 15 for more information regarding this redemption) and to
repurchase other existing indebtedness through open-market and privately
negotiated purchases, and as otherwise permitted by the Company's indentures.
In conjunction with the 2014 Convertible Notes offering, the Company
entered into a ten-year Share Lending Agreement with Deutsche Bank AG London
("DB London"), under which the Company loaned DB London 89 million shares of
newly issued Calpine common stock (the "loaned shares") in exchange for a loan
fee of $.001 per share. The entire 89 million shares were sold by DB London on
September 30, 2004, at a price of $2.75 per share in a registered public
offering. The Company did not receive any of the proceeds of the public
offering. DB London is required to return the loaned shares to the Company no
later than the end of the ten-year term of the Share Lending Agreement, or
earlier under certain circumstances. Once loaned shares are returned, they may
not be re-borrowed under the Share Lending Agreement. Under the Share Lending
Agreement, DB London is required to post and maintain collateral in the form of
cash, government securities, certificates of deposit, high-grade commercial
paper of U.S. issuers or money market shares at least equal to 100% of the
market value of the loaned shares as security for the obligation of DB London to
return the loaned shares to the Company. This collateral is held in an account
at a DB London affiliate. The Company has no access to the collateral unless DB
London defaults under its obligations.
The Company's issuance of 89 million shares of its common stock pursuant to
the Share Lending Agreement was essentially analogous to a sale of shares
coupled with a forward contract for the reacquisition of the shares at a future
date. As there will be no cash consideration for the return of the shares, the
forward contract is considered to be prepaid. This agreement is similar to the
accelerated share repurchase transaction addressed by EITF Issue No. 99-7,
"Accounting for an Accelerated Share Repurchase Program," ("EITF Issue No.
99-7") which is characterized as two distinct transactions: a treasury stock
purchase and a forward sales contract. We have evaluated what is essentially a
prepaid forward contract under the guidance of SFAS No. 133 and EITF Issue No.
00-19: "Accounting for Derivative Financial Instruments Indexed to, and
Potentially Settled in , a Company's Own Stock," and determined that the
instrument meets the requirements to be accounted for in equity and is not
required to be bifurcated and accounted for separate from the Share Lending
Agreement. The transaction was recorded in equity at the fair market value of
the Company's common stock on the date of issuance in the amount of $258.1
million with an offsetting purchase obligation.
Under SFAS No. 150, entities that have entered into a forward contract that
requires physical settlement by repurchase of a fixed number of the issuer's
equity shares of common stock in exchange for cash shall exclude the common
shares to be redeemed or repurchased when calculating basic and diluted earnings
per share. While the Share Lending Agreement does not provide for cash
settlement, physical settlement (i.e. the 89 million shares must be returned by
the end of the agreement) is required. Further, EITF Issue No. 99-7 indicates
that the "treasury stock transaction" would result in an immediate reduction in
number of outstanding shares used to calculate basic and diluted earnings per
share. The share loan is analogous to a prepaid forward contract which would
cancel the shares issued under the Share Lending Agreement and result in an
immediate reduction in the number of outstanding shares used to calculate basic
and diluted earnings per share. Consequently, the Company has excluded the 89
million shares of common stock subject to the Share Lending Agreement from the
earnings per share calculation.
During the three months ended September 30, 2004, the Company repurchased
$734.8 million in principal amount of its outstanding Senior Notes, 2023
Convertible Senior Notes and HIGH TIDES III preferred securities in exchange for
$553.8 million in cash. The Company recorded a pre-tax gain on these
transactions in the amount of $167.2 million, net of write-offs of unamortized
deferred financing costs and the unamortized premiums or discounts.
Annual Debt Maturities
The annual principal repayments or maturities of notes payable and
borrowings under lines of credit, notes payable to the Trusts, preferred
interests, construction/project financing, 4% Convertible Senior Notes Due 2006
("2006 Convertible Senior Notes"), 2014 Convertible Notes, 2023 Convertible
Senior 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 September 30, 2004, are as follows (in thousands):
October through December 2004 (1)...... $ 746,537
2005................................... 482,885
2006................................... 657,529
2007................................... 1,888,584
2008................................... 2,294,280
Thereafter............................. 12,353,265
--------------
Total................................ $ 18,423,080
==============
- ----------
(1) Includes $636.0 million in the aggregate of HIGH TIDES I and HIGH TIDES II
preferred securities that were redeemed subsequent to September 30, 2004.
See Note 15 for more information regarding this redemption.
7. Unrestricted Subsidiaries and Indenture Compliance
Unrestricted Subsidiaries -- The information in this paragraph is required
to be provided under the terms of the indentures and credit agreement governing
the various tranches of the Company's second-priority secured indebtedness
(collectively, the "Second Priority Secured Debt Instruments"). The Company has
designated certain of its subsidiaries as "unrestricted subsidiaries" under the
Second Priority Secured Debt Instruments. A subsidiary with "unrestricted"
status thereunder generally is not required to comply with the covenants
contained therein that are applicable to "restricted subsidiaries." The Company
has designated Calpine Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy
Cogen, L.P. as "unrestricted subsidiaries" for purposes of the Second Priority
Secured Debt Instruments.
Indenture Compliance -- The Company's various indentures place conditions
on the Company's ability to issue indebtedness, including further limitations on
the issuance of additional debt if the Company's interest coverage ratio (as
defined in the various indentures) is below 2:1. Currently, the Company's
interest coverage ratio (as so defined) is below 2:1 and, consequently, the
Company's indentures generally would not allow the Company to issue new debt,
except for (i) certain types of new indebtedness that refinances or replaces
existing indebtedness, and (ii) non-recourse debt and preferred equity interests
issued by subsidiaries of the Company for purposes of financing certain types of
capital expenditures, including plant development, construction and acquisition
expenses. In addition, if and so long as the Company's interest coverage ratio
is below 2:1, the Company's indentures will limit the Company's ability to
invest in unrestricted subsidiaries and non-subsidiary affiliates and make
certain other types of restricted payments.
8. Asset Disposals and 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 September 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.
On September 1, 2004, the Company along with Calpine Natural Gas L.P., a
Delaware limited partnership, completed the sale of its Rocky Mountain gas
reserves that were primarily concentrated in two geographic areas: the Colorado
Piceance Basin and the New Mexico San Juan Basin. Together, these assets
represent approximately 120 billion cubic feet equivalent ("Bcfe") of proved gas
reserves, producing approximately 16.3 million net cubic feet equivalent
("Mmcfe") per day of gas. Under the terms of the agreement Calpine received cash
payments of approximately $222.8 million, and recorded a pre-tax gain of
approximately $102.9 million.
On September 2, 2004, the Company completed the sale of its Canadian
natural gas reserves and petroleum assets. These Canadian assets represent
approximately 221 Bcfe of proved reserves, producing approximately 61 Mmcfe.
Included in this sale was the Company's 25 percent interest in approximately 80
Bcfe of proved reserves (net of royalties) and 32 Mmcfe of production owned by
the CNGT. In accordance with Statement of Financial Accounting Standards No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS
No. 144") the Company's 25% equity method investment in the CNGT was considered
part of the larger disposal group (i.e., assets to be disposed of together as a
group in a single transaction to the same buyer), and therefore evaluated and
accounted for as discontinued operations. Under the terms of the agreement,
Calpine received cash payments of approximately Cdn$825.0 million, or
approximately US$625 million, less adjustments of Cdn$15.6 million, to reflect a
September 2, 2004, closing date. Calpine recorded a pre-tax gain of
approximately $100.6 million on the sale of its Canadian assets.
In connection with the sale of the oil and gas assets in Canada, the
Company entered into a seven-year gas purchase agreement beginning on March 31,
2005, and expiring on October 31, 2011, that allows, but does not require, the
Company to purchase gas from the buyer at current market index prices. The
agreement is not asset specific and can be settled by any production that the
buyer has available.
In connection with the sale of the Rocky Mountain gas reserves, the New
Mexico San Juan Basin sales agreement allows for the buyer and the Company to
execute a ten-year gas purchase agreement for 100% of the underlying gas
production of sold reserves, at market index prices. Any agreement would be
subject to mutually agreeable collateral requirements and other customary terms
and provisions. As of September 30, 2004, no such gas purchase agreement has
been finalized between the Company and the buyer.
The Company believes that all final terms of the gas purchase agreements
described above, are on a market value and arm's length basis. If the Company
elects in the future to exercise a call option over production from the disposed
components, the Company will consider the call obligation to have been met as if
the actual production delivered to the Company under the call was from assets
other than those constituting the disposed components.
Following the sale of oil and gas assets in Canada, $225 million was
repatriated to the United States from the net cash proceeds from the sale of the
Company's Canadian natural gas reserves and petroleum assets which resulted in
an additional U.S. tax liability of approximately $78.8 million in 2004 a
portion of which was part of continuing operations. See Note 15 for further
discussion concerning this tax expense and the Company's expectation of a
partial reduction in the fourth quarter of 2004.
The Company allocates interest to discontinued operations in accordance
with EITF Issue No. 87-24, "Allocation of Interest to Discontinued Operations."
The Company includes interest expense on debt which is required to be repaid as
a result of a disposal transaction in discontinued operations. Additionally,
other interest expense that cannot be attributed to other operations of the
Company is allocated based on the ratio of net assets to be sold less debt that
is required to be paid as a result of the disposal transaction to the sum of
total net assets of the Company plus consolidated debt of the Company, excluding
(a) debt of the discontinued operation that will be assumed by the buyer, (b)
debt that is required to be paid as a result of the disposal transaction and (c)
debt that can be directly attributed to other operations of the Company.
Using the methodology above, the Company allocated interest expense
associated with the debt to be repaid as a result of the sale of the Canadian
natural gas reserves and petroleum assets as well as other debt related to the
Company's operations in the amount of $5.2 million and $17.9 million for the
three and nine months ended September 30, 2004, respectively, and $5.9 million
and $13.3 million for the three and nine months ended September 30, 2003,
respectively.
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 $35.3 million. In addition, CES entered
into a tolling agreement with LCRA providing for the option to purchase 250
megawatts of electricity through December 31, 2004. At December 31, 2003, the
Company's undivided interest in the Lost Pines facility was classified as "held
for sale."
Summary
The Company made reclassifications to current and prior period financial
statements to reflect the sale or designation as "held for sale" of these oil
and gas and power plant assets and liabilities and to separately classify the
operating results of the assets sold and gain on sale of those assets from the
operating results of continuing operations to discontinued operations.
The tables below present significant components of the Company's income
from discontinued operations for the three and nine months ended September 30,
2004, and 2003, respectively (in thousands):
Three Months Ended September 30, 2004
--------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ----------- --------
Total revenue...............................................................$ -- $ 7,576 $ -- $ 7,576
============= ============ =========== ========
Gain on disposal before taxes...............................................$ -- $ 203,533 $ -- $203,533
Operating loss from discontinued operations before taxes.................... -- (258) -- (258)
------------- ------------ ----------- --------
Income from discontinued operations before taxes............................$ -- $ 203,275 $ -- 203,275
============= ============ =========== ========
Gain on disposal, net of tax................................................$ -- $ 62,770 $ -- $ 62,770
Operating loss from discontinued operations, net of tax..................... -- (219) -- (219)
------------- ------------ ----------- --------
Income from discontinued operations, net of tax.............................$ -- $ 62,551 $ -- $ 62,551
============= ============ =========== ========
Three Months Ended September 30, 2003
--------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ----------- --------
Total revenue...............................................................$ 19,238 $ 11,301 $ -- $ 30,539
============= ============ =========== =======
Loss on disposal before taxes...............................................$ -- $ -- $ (8,277) $ (8,277)
Operating income (loss) from discontinued operations before taxes........... 2,144 (341) 6,372 8,175
------------- ------------- ----------- --------
Income (loss) from discontinued operations before taxes.....................$ 2,144 $ (341) $ (1,905) $ (102)
============= ============ =========== ========
Loss on disposal, net of tax................................................$ -- $ -- $ (5,130) $ (5,130)
Operating income (loss) from discontinued operations, net of tax............ 1,393 (185) 4,003 5,211
------------- ------------ ----------- --------
Income (loss) from discontinued operations, net of tax......................$ 1,393 $ (185) $ (1,127) $ 81
============= ============ =========== ========
Nine Months Ended September 30, 2004
--------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ----------- --------
Total revenue...............................................................$ 2,679 $ 28,442 $ -- $ 31,121
============= ============ =========== ========
Gain on disposal before taxes...............................................$ 35,327 $ 207,120 $ -- $242,447
Operating income from discontinued operations before taxes.................. 180 3,090 -- 3,270
------------- ------------ ----------- --------
Income from discontinued operations before taxes............................$ 35,507 $ 210,210 $ -- 245,717
============= ============ =========== ========
Gain on disposal, net of tax................................................$ 22,951 $ 64,952 $ -- $ 87,903
Operating income from discontinued operations, net of tax................... 104 1,920 -- 2,024
------------- ------------ ----------- --------
Income from discontinued operations, net of tax.............................$ 23,055 $ 66,872 $ -- $ 89,927
============= ============ =========== ========
Nine Months Ended September 30, 2003
--------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------ ---------
Total revenue............................................................ $ 58,298 $ 37,964 $ -- $ 96,262
============= ============ =========== ========
Loss on disposal before taxes............................................ $ -- $ -- $ (11,571) $ 11,571)
Operating income (loss) from discontinued operations before taxes........ 5,308 21,853 (6,917) 20,244
------------- ------------ ----------- --------
Income (loss) from discontinued operations before taxes.................. $ 5,308 $ 21,853 $ (18,488) $ 8,673
============= ============ =========== ========
Loss on disposal, net of tax............................................. $ -- $ -- $ (7,172) $ (7,172)
Operating income (loss) from discontinued operations, net of tax......... 3,449 13,372 (4,099) 12,722
------------- ------------ ----------- --------
Income (loss) from discontinued operations, net of tax................... $ 3,449 $ 13,372 $ (11,271) $ 5,550
============= ============ =========== ========
9. 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 its
capital structure to desired levels. Certain of 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.
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 September 30, 2004, for the Company's derivative
instruments:
Commodity
Interest Rate Currency Derivative Total
Derivative Derivative Instruments Derivative
Instruments Instruments Net Instruments
----------- ----------- ----------- -----------
Current derivative assets....................... $ 2,711 $ -- $ 414,219 $ 416,930
Long-term derivative assets..................... -- -- 587,000 587,000
---------- ----------- ----------- -----------
Total assets.................................. $ 2,711 $ -- $ 1,001,219 $ 1,003,930
========== =========== =========== ===========
Current derivative liabilities.................. $ 28,892 $ 12,897 $ 482,236 $ 524,025
Long-term derivative liabilities................ 64,815 -- 576,465 641,280
---------- ----------- ----------- -----------
Total liabilities............................. $ 93,707 $ 12,897 $ 1,058,701 $ 1,165,305
========== =========== =========== ===========
Net derivative liabilities.................. $ 90,996 $ 12,897 $ 57,482 $ 161,375
========== =========== =========== ===========
Of the Company's net derivative position, $321.3 million and $61.3 million
are net derivative assets of PCF and 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.
Below is a reconciliation of the Company's net derivative assets to its
accumulated other comprehensive loss, net of tax from derivative instruments at
September 30, 2004 (in thousands):
Net derivative liabilities....................................................................... $ (161,375)
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness.............. (59,703)
Cash flow hedges terminated prior to maturity.................................................... (83,766)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges...... 89,107
Accumulated OCI from unconsolidated investees.................................................... 35,947
------------
Accumulated other comprehensive loss from derivative instruments, net of tax(1).................. $ (179,790)
============
- ------------
<FN>
(1) Amount represents one portion of the Company's total accumulated OCI
balance. See Note 10 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 September 30, 2004.
September 30, 2004
---------------------------
Gross Net
------------- -----------
Current derivative assets....................... $ 1,035,550 $ 414,219
Long-term derivative assets..................... 1,207,141 587,000
------------- -----------
Total derivative assets....................... $ 2,242,691 $ 1,001,219
============= ===========
Current derivative liabilities.................. $ 1,103,567 $ 482,236
Long-term derivative liabilities................ 1,196,606 576,465
------------- -----------
Total derivative liabilities.................. $ 2,300,173 $ 1,058,701
============= ===========
Net commodity derivative liabilities........ $ (57,482) $ (57,482)
============= ===========
The table above excludes the value of interest rate and currency derivative
instruments.
The tables below reflect the impact of unrealized mark-to-market gains
(losses) on the Company's 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 nine months ended
September 30, 2004 and 2003, respectively (in thousands):
Three Months Ended September 30,
----------------------------------------------------------------------------------------
2004 2003
------------------------------------------- ------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ ---------- --------------- ------------ ---------
Natural gas derivatives(1)....... $ 777 $ (8,508) $ (7,731) $ (4,370) $ 10,562 $ 6,192
Power derivatives(1)............. 1,142 (17,173) (16,031) (115) (17,007) (17,122)
Interest rate derivatives(2)..... 2,369 -- 2,369 (262) -- (262)
Currency derivatives............. -- (12,897) (12,897) -- -- --
------- --------- --------- --------- ---------- -------
Total.......................... $ 4,288 $ (38,578) $ (34,290) $ (4,747) $ (6,445) $(11,192)
======= ========= ========= ======== ========= ========
Nine Months Ended September 30,
----------------------------------------------------------------------------------------
2004 2003
------------------------------------------- ------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ ---------- --------------- ------------ ---------
Natural gas derivatives(1)....... $ 6,540 $ (11,610) $ (5,070) $ 3,810 $ 12,140 $ 15,950
Power derivatives(1)............. 1,268 (53,818) (52,550) (4,753) (30,118) (34,871)
Interest rate derivatives(2)..... 1,421 6,035 7,456 (746) -- (746)
Currency derivatives............. -- (12,897) (12,897) -- -- --
------- --------- --------- -------- --------- --------
Total.......................... $ 9,229 $ (72,290) $ (63,061) $ (1,689) $ (17,978) $(19,667)
======= ========= ========= ======== ========= ========
- ------------
<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 nine months ended September 30, 2004 and 2003,
respectively (in thousands):
Three Months Ended September 30,
--------------------------------
2004 2003
-------------- --------------
Natural gas and crude oil derivatives..... $ (1,746) $ (127)
Power derivatives......................... (26,975) (30,710)
Interest rate derivatives................. (1,320) (4,166)
Foreign currency derivatives.............. (501) (740)
---------- ----------
Total derivatives....................... $ (30,542) $ (35,743)
========== ==========
Nine Months Ended September 30,
--------------------------------
2004 2003
-------------- --------------
Natural gas and crude oil derivatives..... $ 23,487 $ 32,037
Power derivatives......................... (69,998) (86,260)
Interest rate derivatives................. (11,286) (18,259)
Foreign currency derivatives.............. (1,513) 11,089
----------- ----------
Total derivatives....................... $ (59,310) $ (61,393)
=========== ==========
As of September 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 and 12.5 years, for commodity and interest rate derivative
instruments, respectively. The Company estimates that pre-tax losses of $193.2
million would be reclassified from accumulated OCI into earnings during the
twelve months ended September 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................. $ 31,928 $ 49,610 $ 65,916 $ 8,420 $ 885 $ 1,257 $ 158,016
Power OCI............... (53,933) (202,441) (77,856) (3,046) (339) 106 (337,509)
Interest rate OCI....... (7,771) (28,581) (13,563) (8,068) (4,097) (21,713) (83,793)
Foreign currency OCI.... (359) (1,863) (1,863) (1,472) (54) -- (5,611)
-------- --------- -------- ------- ------- -------- ---------
Total pre-tax OCI..... $(30,135) $(183,275) $(27,366) $(4,166) $(3,605) $(20,350) $(268,897)
======== ========= ======== ======= ======= ======== =========
10. 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 nine
months ended September 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 June 30, 2004,
Hedges Investments Translation Income and
September 30,
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
========== ========= ========= =========
Net income for the three months ended September 30, 2004 $ 15,019
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges before
reclassification
adjustment during the three months ended September 30, 2004. $ (76,611)
Reclassification adjustment for loss included in net income
for the
three months ended September 30, 2004....................... 30,542
Income tax benefit for the three months ended September 30,
2004........................................................ 11,773
---------- ---------
(34,296) (34,296) (34,296)
Available-for-sale investments:
Pre-tax gain on available-for-sale investments for the three
months
ended September 30, 2004.................................... 6,183
Income tax provision for the three months ended September 30,
2004........................................................ (2,427)
---------
3,756 3,756 3,756
Foreign currency translation gain for the three months ended
September 30, 2004.......................................... 24,941 24,941 24,941
---------- --------- --------- ---------
Total comprehensive income for the three months ended September
30, 2004....................................................... 9,420
---------
Total comprehensive loss for the nine months ended September 30,
2004........................................................... $(125,009)
=========
Accumulated other comprehensive income (loss) at September 30,
2004........................................................... $ (179,790) $ 3,613 $ 192,633 $ 16,456
========== ========= ========= =========
Comprehensive
Income (Loss)
for the Three
Total Months Ended
Accumulated March 31, 2003,
Other June 30, 2003,
Foreign Comprehensive and
Cash Flow Currency Income September 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)
============ =========== ============
Net income for the three months ended September 30, 2003 $ 237,782
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges before reclassification
adjustment during the three months ended September 30, 2003........... $ 17,732
Reclassification adjustment for loss included in net income for the
three months ended September 30, 2003................................. 35,743
Income tax provision for the three months ended September 30, 2003..... (20,100)
------------
33,375 -- 33,375 33,375
Foreign currency translation loss for the three months ended
September 30, 2003.................................................... -- (2,044) (2,044) (2,044)
------------- ----------- ------------ ----------
Total comprehensive income for the three months ended
September 30, 2003....................................................... $ 269,113
===========
Total comprehensive income for the nine months ended
September 30, 2003....................................................... $ 402,939
===========
Accumulated other comprehensive income (loss) at September 30, 2003........ $ (129,387) $ 132,469 $ 3,082
============ =========== =============
11. Earnings (Loss) per Share
Basic earnings (loss) per common share were computed by dividing net income
(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 and diluted earnings (loss) per common
share is shown in the following table (in thousands, except per share data).
Periods Ended September 30,
2004 2003
-------------------------- --------------------------------
Weighted Weighted
Net Income Average Average
(Loss) Shares EPS Net Income Shares EPS
THREE MONTHS:
Basic earnings (loss) per common share:
Income (loss) before discontinued operations and
cumulative effect of a change in accounting principle $ (47,532) 444,380 $ (0.11) $ 237,701 388,161 $ 0.61
Discontinued operations, net of tax................... 62,551 -- 0.14 81 -- --
Cumulative effect of a change in accounting principle,
net of tax.......................................... -- -- -- -- -- --
---------- ---------- -------- ---------- ---------- --------
Net income........................................ $ 15,019 444,380 $ 0.03 $ 237,782 388,161 $ 0.61
========= ========= ======== ========= ========= ========
Diluted earnings per common share:
Common shares issuable upon exercise of stock options
using treasury stock method......................... -- 6,789
------- ------
Income before dilutive effect of certain convertible
securities, discontinued operations and cumulative
effect of a change in accounting principle.......... $ (47,532) 444,380 $ (0.11 ) $237,701 394,950 $ 0.60
Dilutive effect of certain convertible securities..... -- -- -- 17,788 106,844 (0.09)
Income before discontinued operations and cumulative
effect of a change in accounting principle.......... (47,532) 444,380 (0.11 ) 255,489 501,794 0.51
Discontinued operations, net of tax................... 62,551 -- 0.14 81 -- --
Cumulative effect of a change in accounting principle,
net of tax.......................................... -- -- -- -- -- --
---------- ------- ------ --------- ------- --------
Net income........................................ $ 15,019 444,380 $ 0.03 $255,570 501,794 $ 0.51
========= ======= ======= ======== ======= =======
Periods Ended September 30,
2004 2003
--------------------------- ---------------
Weighted Weighted
Net Income Average Average
(Loss) Shares EPS Net Income Shares EPS
NINE MONTHS:
Basic earnings (loss) per common share:
Income (loss) before discontinued operations and
cumulative effect of a change in accounting principle $ (174,798) 425,682 $ (0.41)$ 156,321 383,447 $ 0.41
Discontinued operations, net of tax................... 89,927 -- 0.21 5,550 -- 0.01
Cumulative effect of a change in accounting principle,
net of tax.......................................... -- -- -- 529 -- --
----------- -------- -------- ------- -------- --------
Net income (loss)................................. $ (84,871) 425,682 $ (0.20)$ 162,400 383,447 $ 0.42
=========== ======= ======== ========= ======= ========
Diluted earnings per common share:
Common shares issuable exercise of stock options using
treasury stock method............................... -- 5,175
------- -------
Income before dilutive effect of certain convertible
securities, discontinued operations and cumulative
effect of a change in accounting principle.......... $(174,798) 425,682 $ (0.41) $156,321 388,622 $ 0.40
Dilutive effect of certain convertible securities..... -- -- -- 32,368 83,607 --
Income before discontinued operations and cumulative
effect of a change in accounting principle.......... (174,798) 425,682 (0.41) 188,689 472,229 0.40
Discontinued operations, net of tax................... 89,927 -- 0.21 5,550 -- 0.01
Cumulative effect of a change in accounting principle,
net of tax.......................................... -- -- -- 529 -- --
---------- ------- -------- -------- -------- -----
Net income............................................ $ (84,871) 425,682 $ (0.20) $194,768 472,229 $ 0.41
========= ======= ==== ======== ======= ====
The Company incurred losses before discontinued operations and cumulative
effect of a change in accounting principle for the three and nine months ended
September 30, 2004. As a result, basic shares were used in the calculations of
fully diluted loss per share for these periods, under the guidelines of SFAS No.
128, "Earnings per Share," ("SFAS No. 128") 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 a weighted average
of 55,072,925 shares of the Company's common stock were not included in the
computation of diluted shares outstanding during the nine months ended September
30, 2004, because such inclusion would be antidilutive. Potentially convertible
securities and unexercised employee stock options to purchase a weighted average
of 41,996,117 shares of the Company's common stock were not included in the
computation of diluted shares outstanding during the nine months ended September
30, 2003, because such inclusion would be antidilutive.
For the three and nine months ended September 30, 2004, approximately 4.0
million and 10.6 million weighted common shares of the Company's outstanding
2006 Convertible Senior Notes were excluded from the diluted EPS calculations as
the inclusion of such shares would have been antidilutive. 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 13.6 million, 11.1 million and
11.9 million weighted average common shares potentially issuable, respectively,
that were excluded from the diluted EPS calculation for the three months ended
September 30, 2004. For the nine month period then ended, respectively, there
were 15.4 million, 13.1 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. All of the convertible preferred securities issued by
Trust I and Trust II were redeemed after September 30, 2004. In addition, $115.0
million of the convertible preferred securities issued by Trust III were
repurchased on September 30, 2004, in a privately negotiated transaction. See
Note 15 for a discussion of the redemption of the convertible preferred
securities issued by Trust I and Trust II.
For the three and nine months ended September 30, 2004, there were no
shares potentially issuable with respect to the Company's 2023 Convertible
Senior Notes. 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 the 2023
Convertible Senior Notes 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 the 2023
Convertible Senior Notes at any time on or after November 22, 2009, in cash for
the face amount plus any accrued and unpaid interest and liquidated damages.
Approximately 138.4 million maximum potential shares are issuable upon
conversion of the 2023 Convertible Senior Notes 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.
For the three and nine months ended September 30, 2004, there were no
shares potentially issuable with respect to the Company's 2014 Convertible
Notes. Upon the occurrence of certain contingencies (generally if the average
trading price as calculated under the prescribed definition exceeds 120% of
$3.85 per share, i.e. $4.62 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 $3.85 per
share. Holders may also surrender the 2014 Convertible Notes for conversion into
cash and shares of the Company's common stock prior to the maturity date at any
time following September 30, 2013. Upon conversion of the 2014 Convertible
Notes, the Company will deliver the portion of the conversion value equal to the
then current principal amount of the 2014 Convertible Notes in cash and any
additional conversion value in Calpine common stock. Approximately 191.2 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
$4.62.
The Company's issuance of 89 million shares of its common stock pursuant to
the Share Lending Agreement was essentially analogous to a sale of shares
coupled with a forward contract for the reacquisition of the shares at a future
date. As there will be no cash consideration for the return of the shares, the
forward contract is considered to be prepaid. This agreement is similar to the
accelerated share repurchase transaction addressed by EITF Issue No. 99-7,
"Accounting for an Accelerated Share Repurchase Program," ("EITF Issue No.
99-7") which is characterized as two distinct transactions: a treasury stock
purchase and a forward sales contract. We have evaluated what is essentially a
prepaid forward contract under the guidance of SFAS No. 133, and determined that
the instrument meets the requirements to be accounted for in equity and is not
required to be bifurcated and accounted for separate from the Share Loan
Agreement. We recorded the transaction in equity at the fair market value of the
Calpine common stock on the date of issuance in the amount of $258.1 million
with an offsetting purchase obligation.
Under SFAS No. 150, entities that have entered into a forward contract that
requires physical settlement by repurchase of a fixed number of the issuer's
equity shares of common stock in exchange for cash shall exclude the common
shares to be redeemed or repurchased when calculating basic and diluted earnings
per share. While the Share Lending Agreement does not provide for cash
settlement, physical settlement (i.e. the 89 million shares must be returned at
the end of the arrangement) is required. Further, EITF Issue No. 99-7 indicates
that the "treasury stock transaction" would result in an immediate reduction in
number of outstanding shares used to calculate basic and diluted earnings per
share. The share loan is analogous to a prepaid forward contract which would
cancel the shares issued under the Share Lending Agreement and result in an
immediate reduction in the number of outstanding shares used to calculate basic
and diluted earnings per share. Consequently, the Company has excluded the 89
million shares of common stock subject to the Share Lending Agreement from the
earnings per share calculation. See Note 6 for more information regarding the
loan of the 89 million shares.
12. Commitments and Contingencies
Turbines. The table below sets forth future turbine payments, net of
expected project financing proceeds, for construction and development projects,
as well as for unassigned turbines. It includes previously delivered turbines,
payments and delivery by year for the remaining three turbines to be delivered
as well as payment required for the potential cancellation costs of the
remaining 39 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 39 turbines.
Units to
Year Total Be Delivered
- ------------------------------------------- ---------- ------------
(In thousands)
October through December 2004.............. $ 33,870 2
2005....................................... 7,932 1
2006....................................... 190 --
---------- -----
Total.................................... $ 41,992 3
========== =====
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, 14 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 11 actions are virtually identical--they are filed by three
law firms, in conjunction with other law firms as co-counsel. All 11 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 14 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 "Ser action"). 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, as amended (the "Securities Act"), 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 15 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 Securities 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 Section 15 of the Securities
Act 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 23, 2004.
In a separate order dated February 4, 2004, the court denied without
prejudice Mr. 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.
In July 2004 the court issued an order for pretrial preparation
establishing a trial date on November 7, 2005. On August 31, 2004, Calpine filed
a motion for summary judgment, which was denied on November 3, 2004. Discovery
is under way. 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. 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. Limited document production has taken
place. Negotiations have been taking place between counsel and further
production of documents will occur once the court enters a protective order
governing the use of confidential information in this action. 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
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 filed its response,
in the form of a motion to dismiss, on or about 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
million, which was approved by the Bankruptcy Court on June 16, 2004. On October
15, 2004, the preference lawsuit was dismissed with prejudice, given that
Calpine had made the final settlement payment prior to that date. Additionally,
the Trustee returned the original Stipulated Judgment to Calpine. Therefore,
this matter has been fully concluded.
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 arising out of an amended Energy Services Agreement ("ESA") by
failing to disclose facts surrounding the termination, effective May 8, 1998, of
one of AELLC's fixed-cost gas supply agreements. The steam price paid by IP
under the ESA is derived from AELLC's cost of gas under its 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).
See Note 15 for an update of this case.
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. On August 17, 2004, the case was transferred to a different
judge, which will likely delay the ruling on the motion to dismiss. 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 20 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 eight other
similar complaints for violations of Section 17200. All eight 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
Section 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. FERC dismissed the complaint in an order issued on
June 26, 2003, and subsequently denied rehearing of that order. The matter is
pending on appeal before the United States Court of Appeals for the Ninth
Circuit.
Transmission Service Agreement with Nevada Power Company. 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 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 certain costs incurred by NPC in
connection with the second phase of the project (approximately $4.5 million in
total to date) 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.
The bond issued by FFIC, by its terms, expired on May 1, 2004. On or about
April 27, 2004, NPC asserted to FFIC that Calpine had committed a default under
the bond by failing to agree to renew or replace the bond upon its expiration
and made demand on FFIC for the full amount of the surety bond, $33,333,333. On
April 29, 2004, FFIC filed a complaint for declaratory relief in state superior
court of Marin County, California in connection with this demand. If FFIC is
successful in its petition, it will be entitled to recover its costs associated
with bringing this action.
FFIC's superior court complaint asks that an order be issued declaring that
it has no obligation to make payment under the bond. Further, if the court were
to determine that FFIC does have an obligation to make payment, FFIC asked 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 filed an answer
denying the allegations of the complaint and asserting affirmative defenses,
including that it has fully performed its obligations under the TSA and surety
bond. NPC filed a motion to quash service for lack of personal jurisdiction in
California.
On September 3, 2004, the superior court granted NPC's motion, and NPC was
dismissed from the proceeding. Subsequently, FFIC agreed to dismiss the
complaint as to Calpine. On September 30, 2004 NPC filed a complaint in state
district court of Clark County, Nevada against Calpine, Moapa Energy Center,
LLC, FFIC and unnamed parties alleging, among other things, breach by Calpine of
its obligations under the TSA and breach by FFIC of its obligations under the
surety bond. At this time, Calpine is unable to predict the outcome of this
proceeding.
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 US$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
US$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 of
National Energy Systems Company ("NESCO"). 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
occurred in September 2004 and the daily reduction in the payment amount has
reduced the $18.0 million payment to zero. Calpine has made the $6 million
payment to the estates. 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 filed a motion to
recover attorneys' fees from NESCO, which was recently granted at a reduced
amount. Calpine held back $100,000 of the $6 million payment to ensure payment
of these fees.
Calpine Energy Services v. Acadia Power Partners. Calpine, through its
subsidiaries, owns 50% of Acadia Power Partners, LLC ("APP") which company owns
the Acadia Energy Center near Eunice, Louisiana (the "Facility"). A Cleco Corp
subsidiary owns the remaining 50% of APP. Calpine Energy Services, LP ("CES") is
the purchaser under two power purchase agreements with APP, which agreements
entitle CES to all of the Facility's capacity and energy. In August 2003 certain
transmission constraints previously unknown to CES and APP began to severely
limit the ability of CES to obtain all of the energy from the Facility. CES has
asserted that it is entitled to certain relief under the purchase agreements, to
which assertions APP disagrees. Accordingly, the parties are engaging in the
initial alternative dispute resolution steps set forth in the power purchase
agreements. It is possible that the dispute will result in binding arbitration
pursuant to the agreements if a settlement is not reached. In addition, CES and
APP are discussing certain billing calculation disputes, which relate to
operating efficiency. The period of time for these disputes is also at issue,
and could range from six months to June 2002 (commercial operation date of
plant). It is expected that the parties will be able to resolve these disputes,
and that APP will owe CES approximately $800,000 to $2.5 million.
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.
13. 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
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 September 30,
Total revenue from external customers... $2,526,955 $2,630,430 $ 17,687 $ 16,578 $ 12,558 $ 9,580 $2,557,200 $2,656,588
Intersegment revenue.................... -- -- 45,833 63,520 -- -- 45,833 71,078
Segment profit/(loss) before provision
for income taxes....................... 9,629 211,015 (19,609) 21,986 29,788 46,010 19,808 279,011
Equipment cancellation and impairment
cost................................... 7,820 632 -- -- -- -- 7,820 632
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 nine months ended September 30,
Total revenue from external customers... $6,799,228 $6,891,958 $ 47,472 $ 45,394 $ 47,006 $ 24,083 $6,893,706 $6,961,435
Intersegment revenue.................... -- -- 157,738 228,669 -- -- 157,738 246,200
Segment profit/(loss) before provision
for income taxes....................... (426,557) 206,390 6,886 62,294 162,918 (101,287) (256,753) 167,397
Equipment cancellation and impairment cost 10,187 19,940 -- -- -- -- 10,187 19,940
Electric Oil and Gas Corporate,
Generation Production Other and
and Marketing and Marketing Eliminations Total
------------- ------------- ------------ ------------
(In thousands)
Total assets:
September 30, 2004..... $ 24,811,792 $ 1,011,337 $ 2,607,790 $ 28,430,919
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.
14. 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
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 FERC
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 resulted in a FERC order issued on March
26, 2004, 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.
State of California, Ex. Rel. Bill Lockyer, Attorney General v. Federal
Energy Regulatory Commission. On September 9, 2004, the Ninth Circuit Court of
Appeals issued a decision on appeal of a Petition for Review of an order issued
by FERC in FERC Docket No. EL02-71 wherein the Attorney General had filed a
complaint (the "AG Complaint") under Sections 205 and 206 of the Federal Power
Act (the "Act") alleging that parties who misreported or did not properly report
market based transactions were in violation of their market based rate tariff
and as a result were not accorded protection under section 206 of the Act from
retroactive refund liability. The Ninth Circuit remanded the order to FERC for
rehearing. FERC is required to determine whether refunds should be required for
violation of reporting requirements prior to October 2, 2000. The proceeding on
remand has not yet been established. In connection with its settlement agreement
with various State of California entities (including the Attorney General),
Calpine and its affiliates settled all claims related to the AG Complaint.
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. 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.
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.
15. Subsequent Events
On October 20, 2004, the Company completed the redemption of its
outstanding 5 3/4% convertible preferred securities issued by Trust I and 5 1/2%
convertible preferred securities issued by Trust II. The redemption price paid
per each $50 principal amount of such convertible preferred securities was $50
plus accrued and unpaid distributions to the redemption date in the amount of
$0.6309 per unit with respect to the convertible preferred securities issued by
Trust I and $0.6035 per unit with respect to the convertible preferred
securities issued by Trust II. All rights of the holders of such convertible
preferred securities have ceased, except the right of such holders to receive
the redemption price, which was deposited with The Depository Trust Company, and
such convertible preferred securities have ceased to be outstanding. In
connection with the redemption of such convertible preferred securities, the
entire outstanding principal amount of Calpine's convertible subordinated
debentures held by Trust I and Trust II were also redeemed and have ceased to be
outstanding. Calpine intends to cause both Trusts to be terminated.
On October 26, 2004, the Company, through its indirect, wholly owned
subsidiary Calpine (Jersey) Limited completed a $360 million offering of
two-year, Redeemable Preferred Shares. The Redeemable Preferred Shares will
distribute dividends priced at 3-month U.S. LIBOR plus 700 basis points to the
shareholders on a quarterly basis. The proceeds of the offering of the
Redeemable Preferred Shares were initially loaned to Calpine's 1,200-megawatt
Saltend cogeneration power plant located in Hull, Yorkshire England, and the
future payments of principal and interest on such loan will fund payments on the
Redeemable Preferred Shares. The net proceeds of the Redeemable Preferred Shares
offering will ultimately be used as permitted by the Company's indentures.
On October 22, 2004, The American Jobs Creation Act of 2004 was signed into
law. In the three months ended September 30, 2004, the Company recorded an
additional tax expense of approximately $78.8 million, which was attributable to
the repatriation of net cash proceeds from Canada to United States following the
sale of oil and gas assets in Canada. While the company continues to evaluate
the impact of the provisions of The American Jobs Creation Act of 2004, the
Company expects at this time to be able to record a reduction of approximately
$66.9 million of this tax expense in the fourth quarter of 2004, most of which
will be reflected in discontinued operations.
On August 31, 2004, Calpine filed a motion for summary judgment to dismiss
the consolidated securities class action lawsuits described above in Note 12. On
November 3, 2004, the court issued an order denying such motion for summary
judgment. Discovery is underway and a trial is scheduled for November 7, 2005.
The Company considers the lawsuit to be without merit and intends to continue to
defend vigorously against these allegations.
The AELLC case described above in Note 12 recently proceeded to trial, and
on November 3, 2004, a jury verdict in the amount of $41 million was rendered in
favor of IP. AELLC was held liable on the misrepresentation claim, but not on
the breach of contract claim. The verdict amount was based on calculations
proffered by IP's damages expert, and AELLC is currently reviewing post-trial
motions and appellate options. AELLC made an additional accrual to recognize the
jury verdict and the Company recognized its 32.3% share.
Subsequent to September 30, 2004, the Company repurchased $200.8 million in
principal amount of its outstanding Senior Notes in exchange for $152.7 million
in cash. The Company recorded a pre-tax gain on these transactions in the amount
of $48.1 million before write-offs of unamortized deferred financing costs and
the unamortized premiums or discounts.
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
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/A, amendment 2, for the year
ended December 31, 2003 and subsequent amendments, and our quarterly reports on
Form 10-Q for the three-month periods ended March 31, 2004 and June 30, 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).
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- -----------------------------
2004 2003 2004 2003
-------------- -------------- -------------- --------------
Power Plants:
Electricity and steam ("E&S") revenues:
Energy............................................... $ 1,201,448 $ 1,011,825 $ 3,098,010 $ 2,540,872
Capacity............................................. 299,944 277,425 709,608 655,282
Thermal and other.................................... 169,755 127,616 422,386 367,039
------------ ------------- ------------- -------------
Subtotal............................................. $ 1,671,147 $ 1,416,866 $ 4,230,004 $ 3,563,193
Spread on sales of purchased power(1).................. 79,424 7,121 135,996 14,542
------------ ------------- ------------- -------------
Adjusted E&S revenues (non-GAAP)....................... $ 1,750,571 $ 1,423,987 $ 4,366,000 $ 3,577,735
Megawatt hours produced................................ 29,390 25,449 72,522 62,069
All-in electricity price per megawatt hour generated... $ 59.56 $ 55.95 $ 60.20 $ 57.64
- ------------
<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 nine months ended September 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 Nine Months Ended
September 30, September 30,
----------------------------- -----------------------------
2004 2003 2004 2003
------------- -------------- ------------- --------------
Total revenue.......................................... $ 2,557,200 $ 2,656,588 $ 6,893,706 $ 6,961,435
Sales of purchased power for hedging
and optimization (1)................................. 430,576 843,013 1,307,256 2,269,102
As a percentage of total revenue....................... 16.8% 31.7% 19.0% 32.6%
Sale of purchased gas for hedging and
optimization......................................... 423,733 305,706 1,258,441 961,652
As a percentage of total revenue....................... 16.6% 11.5% 18.3% 13.8%
Total cost of revenue ("COR").......................... 2,302,797 2,317,716 6,470,300 6,315,176
Purchased power expense for hedging and
optimization (1)..................................... 351,151 835,892 1,171,260 2,254,560
As a percentage of total COR........................... 15.3% 36.1% 18.1% 35.7%
Purchased gas expense for hedging and
optimization......................................... 429,373 293,241 1,243,781 941,312
As a percentage of total COR........................... 18.7% 12.7% 19.2% 14.9%
- ------------
<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," pursuant to 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
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 the 2003 financial
periods prior to our adoption in October 2003 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 Nine Months Ended
September 30, 2003 September 30,2003
------------------ -----------------
(In thousands)
Sales to NEPOOL from power we generated............... $ 88,413 $ 258,945
Sales to NEPOOL from hedging and other activity....... 29,375 117,345
---------- -----------
Total sales to NEPOOL............................... $ 117,788 $ 376,290
Total purchases from NEPOOL......................... $ 99,159 $ 310,025
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
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 in certain market areas. 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 reasonably 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 nine months
ended September 30, 2004 and 2003.
Results of Operations
Three Months Ended September 30, 2004, Compared to Three Months Ended
September 30, 2003 (in millions, except for unit pricing information,
percentages and megawatt volumes).
Revenue
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Total revenue................................................ $ 2,557.2 $ 2,656.6 $ (99.4) (3.7)%
The decrease in total revenue is explained by category below.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Electricity and steam revenue................................ $ 1,671.1 $ 1,416.9 $ 254.2 17.9%
Transmission sales revenue................................... 4.4 4.0 0.4 10.0%
Sales of purchased power for hedging and optimization........ 430.6 843.0 (412.4) (48.9)%
----------- ----------- -----------
Total electric generation and marketing revenue............ $ 2,106.1 $ 2,263.9 $ (157.8) (7.0)%
=========== =========== ===========
Electricity and steam revenue increased as we completed construction and
brought into operation five new baseload power plants and two expansion projects
that were completed subsequent to September 30, 2003. Average megawatts in
operation of our consolidated plants increased by 21.6% to 26,192 MW while
generation increased by 15.5%. In addition, average realized electric price,
before the effects of hedging, balancing and optimization, increased from
$55.67/MWh in 2003 to $56.86/MWh in 2004.
Transmission sales revenue increased during the three months ended
September 30, 2004, as compared to the quarter ended September 30, 2003, as we
brought more plants on-line subsequent to September 30, 2003.
Sales of purchased power for hedging and optimization decreased in the
three months ended September 30, 2004, due primarily to netting approximately
$563.3 of sales of purchased power with purchase power expense in the quarter
ended September 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 $150.9 or 17.9%.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Oil and gas sales............................................ $ 17.7 $ 16.6 $ 1.1 6.6%
Sales of purchased gas for hedging and optimization.......... 423.7 305.7 118.0 38.6%
----------- ----------- -----------
Total oil and gas production and marketing revenue......... $ 441.4 $ 322.3 $ 119.1 37.0%
=========== =========== ===========
Oil and gas sales are net of internal consumption, which is eliminated in
consolidation. Internal consumption decreased from $63.5 in 2003 to $45.8 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 and
the Canadian and United States asset sales that occurred in September 2004.
Before intercompany eliminations oil and gas sales decreased from $80.1 in 2003
to $63.5 in 2004, primarily as a result of reduced production volumes.
Sales of purchased gas for hedging and optimization increased during 2004
due primarily to higher prices of natural gas as compared to the same period in
2003.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Realized gain (loss) on power and gas mark-to-market
transactions, net.......................................... $ 18.7 $ (0.1) $ 18.8 18,800.0%
Unrealized loss on power and gas mark-to-market (23.8) (10.9) (12.9) (118.3)%
transactions, net.......................................... ----------- ----------- -----------
Mark-to-market activities, net........................... $ (5.1) $ (11.0) $ 5.9 (53.6)%
=========== =========== ===========
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 and is offset by a corresponding change in unrealized
gains or losses as unrealized derivative values are converted from unrealized
forward positions to cash at settlement. Unrealized gains and losses include the
change in fair value of open contracts as well as the ineffective portion of our
cash flow hedges.
During the three months ended September 30, 2004, net losses from
mark-to-market activities declined. In the three months ended September 2004 the
Company's exposure to mark-to-market earnings volatility declined commensurate
with a corresponding decline in the volume of open commodity positions
underlying the exposure. As a result, the magnitude of earnings volatility
attributable to any given change in prices declined. Additionally, the Company
recorded a hedge ineffectiveness gain of approximately $1.9 million for the
three months ended September 2004 versus a hedge ineffectiveness loss of $4.5
million for the corresponding period in 2003.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Other revenue................................................ $ 14.7 $ 81.5 $ (66.8) (82.0)%
Other revenue decreased during the three months ended September 30, 2004,
primarily due to a pre-tax gain of $69.4 realized during the three months ended
September 30, 2003, in connection with our settlement with Enron, principally
related to the final negotiated settlement of claims and for amounts owed under
terminated commodity contracts. This decrease was offset partially by revenue
derived from management services performed by our wholly owned subsidiary
Calpine Power Services, Inc. ("CPS") which increased by $3.2 during the three
months ended September 30, 2004, as compared to the same period last year.
Cost of Revenue
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Cost of revenue.............................................. $ 2,302.8 $ 2,317.7 $ (14.9) (0.6)%
The decrease in total cost of revenue is explained by category below.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Plant operating expense...................................... $ 176.3 $ 174.6 $ 1.7 1.0%
Transmission purchase expense................................ 30.8 17.3 13.5 78.0%
Royalty expense.............................................. 8.5 7.0 1.5 21.4%
Purchased power expense for hedging and optimization......... 351.2 835.9 (484.7) (58.0)%
----------- ----------- -----------
Total electric generation and marketing expense........... $ 566.8 $ 1,034.8 $ (468.0) (45.2)%
=========== =========== ===========
Plant operating expense was relatively flat despite new plants coming on
line primarily due to reduced insurance expense in three months ended September
30, 2004.
Transmission purchase expense increased primarily due to additional power
plants achieving commercial operation subsequent to September 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 September 30, 2004, as compared to the same period in 2003
due primarily to netting $563.3 of purchased power expense against sales of
purchased power in the quarter ended September 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.
Without this netting, purchased power expense would have increased by $78.6 or
9.4%.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Oil and gas production expense............................... $ 12.7 $ 13.6 $ (0.9) (6.6)%
Oil and gas exploration expense.............................. 2.0 1.7 0.3 17.7%
----------- ----------- -----------
Oil and gas operating expense.............................. 14.7 15.3 (0.6) (4.0)%
Purchased gas expense for hedging and optimization........... 429.4 293.2 136.2 46.5%
----------- ----------- -----------
Total oil and gas operating and marketing expense........ $ 444.1 $ 308.5 $ 135.6 44.0%
=========== =========== ===========
Oil and gas production expense decreased during the three months ended
September 30, 2004, as compared to the same period in 2003 primarily due to
lower lease operating expense due to lower volumes.
Oil and gas exploration expense increased primarily as a result of an
increase in environmental and reclamation cost.
Purchased gas expense for hedging and optimization increased during the
three months ended September 30, 2004, due primarily to higher prices for
natural gas as compared to the same period in 2003.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Fuel expense
Cost of oil and gas burned by power plants................. $ 1,100.4 $ 807.7 $ 292.7 36.2%
Recognized (gain) loss on gas hedges....................... (2.7) (1.1) (1.6) 145.5%
----------- ----------- -----------
Total fuel expense....................................... $ 1,097.7 $ 806.6 $ 291.1 36.1%
=========== =========== ===========
Cost of oil and gas burned by power plants increased during the three
months ended September 30, 2004 as compared to the same period in 2003 due to a
18% increase in gas consumption and 16% higher prices excluding the effects of
hedging, balancing and optimization.
We recognized a gain on gas hedges during the three months ended September
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
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Depreciation, depletion and amortization expense............. $ 149.3 $ 131.0 $ 18.3 14.0%
Depreciation, depletion and amortization expense increased primarily due to
the additional power facilities in consolidated operations subsequent to
September 30, 2003.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Operating lease expense...................................... $ 25.8 $ 28.4 $ (2.6) (9.2)%
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. As a result, we stopped incurring operating lease expense
on that lease and instead began to incur depreciation and interest expense.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Other cost of revenue........................................ $ 19.2 $ 8.4 $ 10.8 128.6%
Other cost of revenue increased during the three months ended September 30,
2004, as compared to the same period in 2003, due primarily to $1.2 of
additional expense from Power Systems Mfg., LLC ("PSM") and $6.2 of amortization
expense incurred from the adoption of Derivatives Implementation Group ("DIG")
Issue No. C20 ("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 $3.5 of higher expenses at CPS for sale
of engineering, construction and operations services to third parties during the
three months ended September 30, 2004, as compared to the same period last year.
(Income)/Expenses
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
(Income) from unconsolidated investments in power projects... $ 10.9 $ (4.1) $ 15.0 (365.9)%
During the three months ended September 30, 2004, we recorded our share
(approximately $11.6) of a jury award to International Paper at the Androscoggin
Joint Venture Company. For further information, see Note 15 of the Notes to
Consolidated Condensed Financial Statements. Income from our investment in the
Acadia Power Plant decreased by $2.4 from the same period last year partially
due to costs associated with an unscheduled outage. Also, we recognized $0.9
less income this quarter in connection with our investment in the Gordonsville
Power Plant as we sold our interest in the plant in November 2003.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Equipment cancellation and asset impairment cost............. $ 7.8 $ 0.6 $ 7.2 1,200.0%
Equipment cancellation and asset impairment charge increased during the
three months ended September 30, 2004, as compared to the same period in 2003
primarily as a result of a loss of $4.3 recognized in connection with the
impairment charge for one heat recovery steam generator ("HRSG"), a loss on the
sale of 12 tube bundles in the amount of $3.5, and a write-off of $1.8 in
connection with the termination of the purchase contract for one steam turbine
condenser, which was partially offset by a downward adjustment of $1.8 to the
loss recorded on the sale of turbines in 2003.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Long-term service agreement cancellation charge.............. $ 7.6 $ -- $ 7.6 100.0%
A long-term service agreement cancellation charge adjustment of $7.6 was
recorded during the three months ended September 30, 2004, as a result of
settlement negotiations related to the cancellation of long-term service
agreements with Siemens-Westinghouse Power Corporation at our Hermiston,
Ontelaunee, South Point and Sutter facilities.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Project development expense.................................. $ 3.4 $ 3.0 $ 0.4 13.3%
Project development expense increased during the three months ended
September 30, 2004, partially due to costs incurred on oil and gas pipeline and
LNG projects.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Research and development expense............................. $ 4.0 $ 2.8 $ 1.2 42.9%
Research and development expense increased during the three months ended
September 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
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Sales, general and administrative expense.................... $ 58.4 $ 49.4 $ 9.0 18.2%
Sales, general and administrative expense increased during the three months
ended September 30, 2004, primarily due to an increase in employees or employee
costs, consulting, rent, insurance and other professional fees. Over half of the
increase is directly attributable to the Sarbanes-Oxley Section 404 internal
controls project and audit work related thereto.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Interest expense............................................. $ 293.6 $ 198.7 $ 94.9 47.8%
Interest expense increased as a result of higher average debt balances,
higher average interest rates and lower capitalization of interest expense.
Interest capitalized decreased as a result of new plants that entered commercial
operations (at which point capitalization of interest expense ceases) from $98.7
for the three months ended September 30, 2003, to $86.8 for the three months
ended September 30, 2004. We expect that the amount of interest capitalized will
continue to decrease in future periods as our plants in construction are
completed. Additionally, during the three months ended September 30, 2004, (i)
interest expense related to the Company's senior notes and term loans increased
$9.6; (ii) interest expense related to the Company's Calpine Generating Company,
LLC ("CalGen") subsidiary (formerly CCFC II) increased $25.8; (iii) interest
expense related to the Company's construction/project financing increased $18.1;
(iv) interest expense related to the Company's Calpine Construction Finance
Company L.P. ("CCFC I") subsidiary increased $6.1; and (v) interest expense
related to the Company's preferred interests increased $5.0. The majority of the
remaining increase relates to a increase in average indebtedness due primarily
to the deconsolidation of Calpine Capital Trust I ("Trust I"), Calpine Capital
Trust II ("Trust II") and Calpine Capital Trust III ("Trust III" and together
with Trust I and Trust II, the "Trusts") and the recording of debt to the 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. Interest expense related
to the Notes payable to the Trusts during the three months ended September 30,
2004, was $16.5; during the three months ended September 30, 2003, this expense
was classified as Distributions on Trust Preferred Securities and amounted to
$15.3. As the distributions were excluded from the interest expense caption on
the Company's Consolidated Condensed Statements of Operations for the three
months ended September 30, 2003, this represents a $16.5 increase to interest
expense during the three months ended September 30, 2004, but there was only a
$1.2 increase in the distributions paid during the three months ended September
30, 2004.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Distributions on Trust Preferred Securities.................. $ -- $ 15.3 $ (15.3) (100.0)%
As discussed above, as a result of the deconsolidation of the Trusts upon
adoption of FIN 46 as of October 1, 2003, the distributions paid on the Trust
Preferred Securities during the three months ended September 30, 2004, were no
longer recorded on our books and were replaced prospectively by interest expense
on our debt to the Trusts.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Interest (income)............................................ $ (17.2) $ (10.7) $ 6.5 60.7%
Interest (income) increased during the three months ended September 30,
2004, due primarily to an increase in cash and equivalents and restricted cash
balances as compared to the same period in 2003.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Minority interest expense.................................... $ 10.0 $ 2.6 $ 7.4 284.6%
Minority interest expense increased during the three months ended September
30, 2004, as compared to the same period in 2003 primarily due to our reduced
ownership percentage in the Calpine Power Limited Partnership ("CPLP") following
the sale of our interest in the Calpine Power Income Fund ("CPIF"), which owns
70% of CPLP.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
(Income) from repurchases of various issuances of debt....... $ (167.2) $ (207.2) $ (40.0) (19.3)%
For the three month ended September 30, 2004, income from the repurchases
of debt decreased by $40.0 from the corresponding period in the prior year
primarily as a result of less open market and privately negotiated transactions.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Other expense................................................ $ 23.3 $ 9.5 $ 13.8 145.3%
Other expense increased by $13.8 in the three months ended September 30,
2004, compared to the prior year due primarily to foreign currency transaction
losses increasing by $20.4 from the corresponding period in 2003. This was
partially mitigated by lower charges associated with refinancings.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Provision for income taxes................................... $ 67.3 $ 41.3 $ 26.0 62.9%
For the three months ended September 30, 2004, our effective rate increased
to 340% as compared to 15% for the three months ended September 30, 2003. This
effective rate increase is primarily due to the repatriation of net cash
proceeds from Canada to the United States from the sale of oil and gas assets in
Canada and the unfavorable impact of the sale or the tax benefits related to our
cross border financings. It is also due to the consideration of estimated full
year earnings in estimating the effective rate, and truing up to on a
year-to-date basis, the annual effective rate. On October 22, 2004, The American
Jobs Creation Act of 2004 was signed into law. In the three months ended
September 30, 2004, we recorded an additional tax expense of approximately $78.8
million, which was attributable to the repatriation of net cash proceeds from
Canada to United States following the sale of oil and gas assets in Canada.
While we continue to evaluate the impact of the provisions of The American Jobs
Creation Act of 2004, we expect at this time to be able to record a reduction of
approximately $66.9 million of this tax expense in the fourth quarter of 2004,
most of which will be reflected in discontinued operations.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Discontinued operations, net of tax.......................... $ 62.6 $ 0.1 $ 62.5 62,500.0%
During the three months ended September 30, 2004, discontinued operations
activity was related to the sale of our gas reserves in the Colorado Piceance
Basin and New Mexico San Juan Basin and the sale of our Canadian natural gas
reserves and petroleum assets, which resulted in a pre-tax gain of $203.5 and
tax charge of $78.8 related to the repatriation of $225 of the proceeds of the
Canadian oil and gas sale in addition to income taxes at the statutory rate.
Three Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Net income................................................... $ 15.0 $ 237.8 $ (222.8) (93.7)%
In the quarter ended September 30, 2004, the Company netted approximately
$563.3 of sales of purchased power for hedging and optimization with purchased
power expense for hedging and optimization. This was due to the adoption of EITF
Issue No. 03-11. Without this netting, total revenue would have grown by
approximately 17% versus the reported 4% reduction in revenue. For the three
months ended September 30, 2004, the company reported net income of $15.0,
compared to net income of $237.8, for the same quarter in the prior year. On
October 22, 2004, The American Jobs Creation Act of 2004 was signed into law. In
the three months ended September 30, 2004, we recorded an additional tax expense
of approximately $78.8 million, which was attributable to the repatriation of
net cash proceeds from Canada to United States following the sale of oil and gas
assets in Canada. While we continue to evaluate the impact of the provisions of
The American Jobs Creation Act of 2004, we expect at this time to be able to
record a reduction of approximately $66.9 million of this tax expense in the
fourth quarter of 2004, most of which will be reflected in discontinued
operations.
We recognized an after-tax gain of $62.6 in discontinued operations
associated with the sale of our Canadian natural gas reserves and petroleum
assets and the sale of our gas reserves in the Colorado Piceance Basin and New
Mexico San Juan Basin. We also recognized a pre-tax gain on the repurchase of
certain debt issuances in the amount of $167.2 in the third quarter of 2004.
Gross profit decreased by $84.5, or 25%, to $254.4 in the three months
ended September 30, 2004, primarily due to: i) non-recurring other revenue of
$69.4 recognized in the third quarter of 2003 from the settlement of contract
disputes with, and claims against, Enron Corp.; ii) the amortization of $6.2 in
the third quarter of 2004 of the DIG Issue No. C20 gain recorded in the fourth
quarter of 2003 due to the cumulative effect of a change in accounting
principle; iii) soft market fundamentals, which caused total spark spread to not
increase commensurately with additional transmission purchase expense, and
depreciation costs associated with new power plants coming on-line. During the
three months ended September 30, 2004, financial results were affected by a
$79.7 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. Loss before
discontinued operations and cumulative effect of a change in accounting
principle was $47.5. This loss is primarily due to an effective tax rate
increase, which occurred as a result of the sale of oil and gas assets in Canada
and due to the repatriation of cash to the United States.
For the three months ended September 30, 2004, we generated 29.4 million
megawatt-hours, which equated to a baseload capacity factor of 56%, and realized
an average spark spread of $21.40 per megawatt-hour. For the same period in
2003, we generated 25.4 million megawatt-hours, which equated to a capacity
factor of 60%, and realized an average spark spread of $23.88 per megawatt-hour.
Nine Months Ended September 30, 2004, Compared to Nine Months Ended
September 30, 2003 (in millions, except for unit pricing information,
percentages and megawatt volumes).
Revenue
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Total revenue................................................ $ 6,893.7 $ 6,961.4 $ (67.7) (1.0)%
The increase in total revenue is explained by category below.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Electricity and steam revenue................................ $ 4,230.0 $ 3,563.2 $ 666.8 18.7%
Transmission sales revenue................................... 14.1 13.2 0.9 6.8%
Sales of purchased power for hedging and optimization........ 1,307.3 2,269.1 (961.8) (42.4)%
----------- ----------- ----------
Total electric generation and marketing revenue............ $ 5,551.4 $ 5,845.5 $ (294.1) (5.0)%
=========== =========== ==========
Electricity and steam revenue increased as we completed construction and
brought into operation five new baseload power plants and two expansion projects
completed subsequent to September 30, 2003. Average megawatts in operation of
our consolidated plants increased by 22.8% to 24,108 MW while generation
increased by 16.8%. The increase in generation lagged behind the increase in
average MW in operation as our baseload capacity factor dropped to 51% in the
nine months ended September 30, 2004, from 55% in the nine months ended
September 30, 2003, primarily due to the increased occurrence of unattractive
off-peak market spark spreads in certain areas reflecting mild weather in the
first and third quarters of 2004 and 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 $57.41/MWh in 2003 to $58.33/MWh in 2004.
Sales of purchased power for hedging and optimization decreased in the nine
months ended September 30, 2004, due primarily to netting approximately $1,255.8
of sales of purchased power with purchase power expense in the nine months ended
September 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 $294.0 or
13.0%.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Oil and gas sales............................................ $ 47.5 $ 45.4 $ 2.1 4.6%
Sales of purchased gas for hedging and optimization.......... 1,258.4 961.6 296.8 30.9%
----------- ----------- ----------
Total oil and gas production and marketing revenue......... $ 1,305.9 $ 1,007.0 $ 298.9 29.7%
=========== =========== ==========
Oil and gas sales are net of internal consumption, which is eliminated in
consolidation. Internal consumption decreased primarily as a result of lower
production, from $228.7 in 2003 to $157.7 in 2004. Before intercompany
eliminations, oil and gas sales decreased by 25.1% or $68.9 to $205.2 in 2004
from $274.1 in 2003 due to lower production volumes.
Sales of purchased gas for hedging and optimization increased during 2004
due primarily to higher prices of natural gas as compared to the same period in
2003.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Realized gain on power and gas mark-to-market transactions,
net........................................................ $ 42.4 $ 30.2 $ 12.2 40.4%
Unrealized loss on power and gas mark-to-market
transactions, net.......................................... (57.6) (18.9) (38.7) 204.8%
----------- ----------- ----------
Mark-to-market activities, net............................. $ (15.2) $ 11.3 $ (26.5) (234.5)%
=========== =========== ==========
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, 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 and is offset by a corresponding
change in unrealized gains or losses as unrealized derivative values are
converted from unrealized forward positions to cash at settlement. Unrealized
gains and losses include the change in fair value of open contracts as well as
the ineffective portion of our cash flow hedges.
Losses from mark-to-market activities increased in the nine months ended
September 30, 2004, as compared to the corresponding period in 2004 primarily
due to mark-to-market losses incurred on one of our long-term derivative
contracts resulting from unfavorable price movements against the contract.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Other revenue................................................ $ 51.6 $ 97.6 $ (46.0) (47.1)%
Other revenue decreased during the nine months ended September 30, 2004,
primarily due to a pre-tax gain of $69.4 realized during the nine months ended
September 30, 2003, in connection with our settlement with Enron, principally
related to the final negotiated settlement of claims and amounts owed under
terminated commodity contracts. This decrease was partially offset by revenue
from TTS which increased by $13.5 as compared to the same period last year.
Additionally, revenue from CPS increased $8.5 as compared to the same period
last year.
Cost of Revenue
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Cost of revenue.............................................. $ 6,470.3 $ 6,315.2 $ 155.1 2.5%
The increase in total cost of revenue is explained by category below.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Plant operating expense...................................... $ 575.8 $ 496.1 $ 79.7 16.1%
Transmission purchase expense................................ 61.9 37.5 24.4 65.1%
Royalty expense.............................................. 21.3 18.8 2.5 13.3%
Purchased power expense for hedging and optimization......... 1,171.3 2,254.6 (1,083.3) (48.0)%
----------- ----------- ----------
Total electric generation and marketing expense............ $ 1,830.3 $ 2,807.0 $ (976.7) (34.8)%
=========== =========== ==========
Plant operating expense increased due to five new baseload power plants and
two expansion projects completed subsequent to September 30, 2003, and due to
higher maintenance expenses of existing plants as many of our newer plants began
their initial major maintenance work.
Transmission purchase expense increased primarily due to additional power
plants achieving commercial operation subsequent to September 30, 2003.
Approximately 76% of the royalty expense for the nine months ended
September 30, 2004, 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 nine months 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
nine months ended September 30, 2004, as compared to the same period in 2003 due
primarily to netting $1,255.8 of purchased power expense against sales of
purchased power in the nine months ended September 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. Without this netting, purchased power expense would
have increased by $172.5 or 7.7%.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Oil and gas production expense............................... $ 36.4 $ 43.1 $ (6.7) (15.6)%
Oil and gas exploration expense.............................. 6.4 10.5 (4.1) (39.0)%
----------- ----------- ----------
Oil and gas operating expense.............................. 42.8 53.6 (10.8) (20.1)%
Purchased gas expense for hedging and optimization........... 1,243.8 941.3 302.5 32.1%
----------- ----------- ----------
Total oil and gas operating and marketing expense........ $ 1,286.6 $ 994.9 $ 291.7 29.3%
=========== =========== ==========
Oil and gas production expense decreased during the nine months ended
September 30, 2004, as compared to the same period in 2003 primarily due to
lower lease operating expense resulting from lower production volumes.
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
nine months ended September 30, 2004, due primarily to higher prices of natural
gas as compared to the same period in 2003.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Fuel expense
Cost of oil and gas burned by power plants................. $ 2,804.1 $ 2,040.6 $ 763.5 37.4%
Recognized (gain) on gas hedges............................ (20.6) (5.3) (15.3) 288.7%
----------- ----------- ----------
Total fuel expense....................................... $ 2,783.5 $ 2,035.3 $ 748.2 36.8%
=========== =========== ==========
Cost of oil and gas burned by power plants increased during the nine months
ended September 30, 2004 as compared to the same period in 2003 due to a 22%
increase in gas consumption and 12% higher prices for gas excluding the effects
of hedging, balancing and optimization.
We recognized a larger gain on gas hedges during the nine months ended
September 30, 2004, as compared to the same period in 2003 due to favorable gas
price movements relative to our gas financial instrument positions.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Depreciation, depletion and amortization expense............. $ 421.0 $ 373.1 $ 47.9 12.8%
Depreciation, depletion and amortization expense increased primarily due to
the additional power facilities in consolidated operations subsequent to
September 30, 2003.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Operating lease expense...................................... $ 80.6 $ 84.3 $ (3.7) (4.4)%
Operating lease expense decreased from the prior year as the King City
lease terms were restructured in May 2004 and the lease began to be accounted
for as a capital lease at that point. As a result, we ceased incurring operating
lease expense on that lease and instead began to incur depreciation and interest
expense.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Other cost of revenue........................................ $ 68.2 $ 20.5 $ 47.7 232.7%
Other cost of revenue increased during the nine months ended September 30,
2004, as compared to the same period in 2003 due primarily to $10.5 of
additional expense from TTS and $22.9 of amortization expense incurred from the
adoption of DIG Issue No. C20. 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 $8.8 higher costs at CPS due to a higher level
of activity in 2004.
(Income)/Expenses
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Loss (income) from unconsolidated investments in power
projects................................................... $ 11.7 $ (68.6) $ 80.3 (117.1)%
During the nine months ended September 30, 2003, we recorded a $52.8 gain,
our 50% share, on the termination of the tolling arrangement with Aquila
Merchant Services, Inc. at the Acadia Power Plant. For the same period, we
recognized $4.2 of income on Gordonsville Power Plant. We did not have any
income on our Gordonsville investment in 2004, as we sold our interests in this
facility in November 2003. In addition, in 2004 we recognized $8.7 less income
on the Acadia investment, and $3.7 more loss from the Aries investment, which we
began to consolidate in March 2004 when we purchased the remaining 50% interest
in March 2004 from Aquila. We also recorded our share (approximately $11.6) of a
jury award to International Paper at the Androscoggin Joint Venture Company.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Equipment cancellation and asset impairment cost............. $ 10.2 $ 19.9 $ (9.7) (48.7)%
Equipment cancellation and asset impairment charge decreased during the
nine months ended September 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.
During the nine months ended September 30, 2004, we incurred $2.3 in connection
with the termination of a purchase contract for heat recovery steam generator
components, $4.3 in connection with the impairment charge for one HRSG, a loss
on the sale of 12 tube bundles in the amount of $3.5, and a write-off of $1.8 in
connection with the termination of the purchase contract for one steam turbine
condenser and a downward adjustment of $1.8 for the loss recorded in 2003 on the
sale of turbines.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Long-term service agreement cancellation charge.............. $ 7.6 $ -- $ 7.6 100.0%
Long-term service agreement cancellation charge adjustment of $7.6 was
recorded during the nine months ended September 30, 2004, as a result of
settlement negotiations related to the cancellation of long-term service
agreements with Siemens-Westinghouse Power Corporation at our Hermiston,
Ontelaunee, South Point and Sutter facilities.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Project development expense.................................. $ 15.1 $ 14.1 $ 1.0 7.1%
Project development expense increased during the nine months ended
September 30, 2004, partly due to higher costs associated with cancelled
projects, and due to costs incurred on oil and gas pipeline and LNG projects.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Research and development expense............................. $ 12.9 $ 7.7 $ 5.2 67.5%
Research and development expense increased during the nine months ended
September 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.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Sales, general and administrative expense.................... $ 171.0 $ 142.8 $ 28.2 19.7%
Sales, general and administrative expense increased during the nine months
ended September 30, 2004, primarily due to an increase in employees or employee
costs, consulting, rent, insurance and other professional fees. Over a third of
the variance is directly attributable to the Sarbanes-Oxley Section 404 internal
control project and related audit work.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Interest expense............................................. $ 815.4 $ 483.2 $ 332.2 68.8%
Interest expense increased as a result of higher average debt balances,
higher average interest rates and lower capitalization of interest expense.
Interest capitalized decreased as a result of new plants that entered commercial
operations (at which point capitalization of interest expense ceases) from
$333.7 for the nine months ended September 30, 2003, to $297.4 for the nine
months ended September 30, 2004. We expect that the amount of interest
capitalized will continue to decrease in future periods as our plants in
construction are completed. Additionally, during the nine months ended September
30, 2004, (i) interest expense related to the Company's senior notes and term
loans increased $115.9; (ii) interest expense related to the Company's CalGen
financing was responsible for an increase of $78.8; (iii) interest expense
related to the Company's notes payable and borrowings under lines of credit
increased $41.6; (iv) interest expense related to the Company's CCFC I financing
increased $23.1; and (v) interest expense related to the Company's preferred
interests increased $25.8. The majority of the remaining increase relates to a
increase in average indebtedness due primarily to the deconsolidation of the
Trusts and the recording of debt to the Trusts due to the adoption of 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.
Interest expense related to the notes payable to the Trusts during the nine
months ended September 30, 2004, was $47.8; during the nine months ended
September 30, 2003, this expense was classified as Distributions on Trust
Preferred Securities and amounted to $46.6. As the distributions were excluded
from the interest expense caption on the Company's Consolidated Condensed
Statements of Operations for the nine months ended September 30, 2003, this
represents a $47.8 increase to interest expense during the nine months ended
September 30, 2004, but there was only a $1.2 increase in the distributions paid
during the nine months ended September 30, 2004.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Distributions on Trust Preferred Securities.................. $ -- $ 46.6 $ (46.6) (100.0)%
As discussed above, as a result of the deconsolidation of the Trusts upon
adoption of FIN 46 as of October 1, 2003, the distributions paid on the Trust
Preferred Securities during the nine months ended September 30, 2004, were no
longer recorded on our books and were replaced prospectively by interest expense
on our debt to the Trusts.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Interest (income)............................................ $ (39.2) $ (27.8) $ (11.4) 41.0%
Interest (income) increased during the nine months ended September 30,
2004, primarily due to an increase in cash and equivalents and restricted cash
balances as compared to the same period in 2003.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Minority interest expense.................................... $ 23.1 $ 10.2 $ 12.9 126.5%
Minority interest expense increased during the nine months ended September
30, 2004, as compared to the same period in 2003 primarily due to an increase in
expense of $13.6 related to our reduced ownership percentage in CPLP.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
(Income) from repurchase of various issuances of debt........ $ (170.5) $ (214.0) $ 43.5 (20.3)%
Income from repurchases of various issuances of debt during the nine months
ended September 30, 2004, decreased by $43.5 from the corresponding period
primarily as a result of less open market and privately negotiated transactions.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Other expense (income)....................................... $ (177.1) $ 64.6 $ (241.7) (374.1)%
Other expense (income) increased by $241.7 during the nine months ended
September 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
Utility Contract Funding II, LLC ("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 nine months ended
September 30, 2004, foreign currency transaction losses were $7.5 compared to a
loss of $36.2 in the corresponding period in 2003. During the nine months ended
September 3, 2003, Letter of Credit Fees were $10.5.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Provision (benefit) for income taxes......................... $ 82.0 $ 11.1 $ 70.9 (638.7)%
For the nine months ended September 30, 2004, the effective rate was a
benefit of 32% as compared to a provision of 7% for the nine months ended
September 30, 2003. This change in the effective rate is primarily due to the
repatriation of net cash proceeds from Canada to the United States from the sale
of oil and gas assets in Canada. It is also due to the consideration of
estimated full year earnings in estimating our effective rate, and truing up on
a year-to-date basis, the annual effective rate and due to the effect of
significant permanent items, primarily related to cross border financings.
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Discontinued operations, net of tax.......................... $ 89.9 $ 5.6 $ 84.3 1,505.4%
In the nine months ended September 30, 2004, discontinued operations were
comprised primarily of the gain, net of tax, from the sale of our 50% interest
in the Lost Pines 1 Power Project of $23.0 and the sale of our oil and gas
reserves in the Colorado Piceance Basin and New Mexico San Juan Basin and the
sale of our Canadian natural gas reserves and petroleum assets. The latter sale
resulted in a gain, net of tax, of $65.0. During the nine months ended September
30, 2003, discontinued operations activity included the operational reclasses to
discontinued operations related to our 50% interest in the Lost Pines 1 Energy
Center, the sale of certain of our oil and gas assets in the United States and
Canada and the sale of our specialty data center engineering business.
Nine Months Ended
September 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."
Nine Months Ended
September 30,
2004 2003 $ Change % Change
----------- ----------- ------------ -----------
Net loss..................................................... $ (84.9) $ 162.4 $ (247.3) (152.3)%
In the nine months ended September 30, 2004, the Company netted
approximately $1.26 billion of sales of purchased power for hedging and
optimization with purchased power expense. This was due to the adoption of EITF
Issue No. 03-11. Without this netting, total revenue would have grown by
approximately 17% versus the reported 1% reduction in revenue. For the nine
months ended September 30, 2004, we reported a net loss of $84.9, compared to
net income of $162.4, for the same period in the prior year. On October 22,
2004, The American Jobs Creation Act of 2004 was signed into law. In the nine
months ended September 30, 2004, we recorded an additional tax expense of
approximately $78.8 million, which was attributable to the repatriation of net
cash proceeds from Canada to United States following the sale of oil and gas
assets in Canada. While we continue to evaluate the impact of the provisions of
The American Jobs Creation Act of 2004, we expect at this time to be able to
record a reduction of approximately $66.9 million of this tax expense in the
fourth quarter of 2004, most of which will be reflected in discontinued
operations.
Gross profit decreased by $222.9, or 34%, to $423.4 in the nine months
ended September 30, 2004, primarily due to: i) non-recurring other revenue of
$69.4 recognized in the third quarter of 2003 from the settlement of contract
disputes with, and claims against, Enron Corp.; ii) the amortization of $22.9 in
the first nine months of 2004 of the DIG Issue No. C20 gain recorded in the
fourth quarter of 2003 due to the cumulative effect of a change in accounting
principle; iii) soft market fundamentals, which caused total spark spread to not
increase commensurately with additional plant operating expense and transmission
purchase expense, and depreciation costs associated with new power plants coming
on-line. During the nine months ended September 30, 2004, financial results were
affected by a $285.5 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.
Prior year results benefited from recording $52.8 (in income from unconsolidated
investments in power projects) from termination of a power purchase agreement by
the Acadia joint venture.
Other income increased by $241.7 during the nine months ended September 30,
2004, as compared to the same period in 2003, primarily due to: i) pre-tax
income in the amount of $171.5, net of transaction costs and the write-off of
unamortized deferred financing costs associated with the restructuring of power
purchase agreements for the company's Newark and Parlin power plants and the
sale of an entity holding a power purchase agreement; ii) a $16.4 pre-tax gain
from the restructuring of a long-term gas supply contract net of transaction
costs; and iii) 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 nine months ended September 30, 2004, foreign currency transaction losses
were $7.5, compared to a loss of $36.2 in the corresponding period in 2003. We
recognized a gain of $170.5 in the nine months ended September 30, 2004 on the
repurchase of certain debt issuances, and loss before discontinued operations
and cumulative effect of a change in accounting principle was $167.5 in the nine
months ended September 30, 2004.
Discontinued operations, net of tax increased by $84.4 during the nine
months ended September 30, 2004, as compared to the same period in 2003, as a
result of the sale of oil and gas assets in the United States and Canada during
the third quarter of 2004 and the sale of the company's interest in the Lost
Pines facility in the first quarter of 2004.
For the nine months ended September 30, 2004, the company generated 72.5
million megawatt-hours, which equated to a baseload capacity factor of 51%, and
realized an average spark spread of $21.19 per megawatt-hour. For the same
period in 2003, we generated 62.1 million megawatt-hours, which equated to a
capacity factor of 55%, and realized an average spark spread of $23.90 per
megawatt-hour.
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 credit facilities;
issuance of debt, equity, trust preferred securities and convertible debentures
and contingent convertible notes; 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 pay
debt obligations, fund acquisitions, develop and construct power generation
facilities, finance capital expenditures, support our hedging, balancing,
optimization and trading activities, 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 common stock or a
combination of the two. In 2003 and 2004 we repurchased 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 Senior Notes") in November 2003.The
repurchases were made in open market and privately negotiated transactions and,
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
September 30, 2004, an aggregate principal amount of $72.1 million of 2006
Convertible Senior Notes remain outstanding.
Subsequent to September 30, 2004, all of our outstanding HIGH TIDES I and
HIGH TIDES II preferred securities were redeemed. See Note 15 of the Notes to
Consolidated Condensed Financial Statements for information related to the
redemption of all outstanding HIGH TIDES I preferred securities and HIGH TIDES
II preferred securities. In addition, $517.5 million of our HIGH TIDES III are
scheduled to be remarketed no later than August 1, 2005. We repurchased $115.0
million of HIGH TIDES III during the quarter ended September 30, 2004. 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 September 30, 2004.
See Note 6 of the Notes to Consolidated Condensed Financial Statements for
more information related to other financings and repurchases of various
issuances of debt in the third quarter of 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 September 30, 2004, our liquidity totaled approximately $2.7
billion. This included cash and cash equivalents on hand of $1.5 billion,
current portion of restricted cash and of approximately $0.9 billion and
approximately $0.3 billion of borrowing capacity under our various credit
facilities.
Cash Flow Activities -- The following table summarizes our cash flow
activities for the periods indicated:
Nine Months Ended
September 30,
2004 2003
------------- --------------
(In thousands)
Beginning cash and cash equivalents.................................. $ 991,806 $ 579,486
Net cash provided by (used in):
Operating activities............................................... 229,870 171,332
Investing activities............................................... (381,934) (1,836,581)
Financing activities............................................... 633,703 2,046,489
Effect of exchange rates changes on cash and cash equivalents...... 14,377 8,946
------------ --------------
Net decrease in cash and cash equivalents.......................... 496,016 390,186
------------ --------------
Ending cash and cash equivalents..................................... $ 1,487,822 $ 969,672
============ ==============
Operating activities for the nine months ended September 30, 2004, provided
net cash of $229.9 million, compared to $171.3 million for the same period in
2003. Operating cash flows in 2004 benefited from the receipt of $100.6 million
from the termination 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 nine months of 2004, there was a $12.0 million use of
funds from net changes in operating assets and liabilities. Uses of funds
included accounts receivable, which increased by $104.8 million as our total
revenues in the first nine months of 2004 (adjusted for the netting of
approximately $1.3 billion of purchase power expense with sales of purchased
power pursuant to EITF 03-11) increased by approximately $1.2 billion. Also,
cash operating lease payments exceeded recognized expense by $53.7 million and
accrued liabilities were reduced, through payments, for sales and property
taxes. These uses of funds were partially offset by an increase of $218.9
million in accounts payable and accrued liabilities (including an increase in
interest expense payable of $44.6 million) and a $14.1 million decrease in net
margin deposits posted to support CES contracting activity.
In the first nine months of 2003, operating cash flows benefited from a
$105.5 million distribution from the Acadia joint venture, following the
termination of the power purchase agreement with Aquila and the restructuring of
our interest in the joint venture. We also used $638.0 million of funds for net
changes in operating assets and liabilities, which primarily resulted from
higher accounts receivable balances, higher net margin deposits and prepaid gas
balances to support our contracting activity in 2003, and lower accounts payable
balances.
Investing activities for the nine months ended September 30, 2004, consumed
net cash of $381.9 million, as compared to $1,836.6 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 $148.6 million from the sale of our
50% interest in the Lost Pines I Power Plant, $626.6 million from the sale of
our Canadian oil and gas reserves, $219.1 million from the sale of our Rocky
Mountain oil and gas reserves, together with the proceeds from the sale of a
subsidiary holding power purchase agreements for two of our New Jersey power
plants. These sales compare to $15.2 million of proceeds from disposals in the
prior year. We also reported a $181.0 million increase in cash used for
acquisitions in 2004 compared to 2003, as we used the proceeds from the Lost
Pines sale and cash to purchase the Los Brazos Power Plant, and we used cash on
hand to purchase the remaining 50% interest in the Aries Power Plant and the
remaining 20% interest in Calpine Cogeneration Corporation. Also, we used $111.6
million to purchase a portion of High Tides III and invested $124.2 million in
restricted cash during 2004.
Financing activities for the nine months ended September 30, 2004, provided
$633.7 million, compared to $2,046.5 million for the same period in 2003. We
continued our refinancing program in 2004, by raising $2.6 billion to repay $2.3
billion of CalGen project financing. In 2004 we also raised $250 million from
the issuance of 2023 Convertible Senior Notes pursuant to an option exercise by
one of the initial purchasers and $617.5 from the issuance of the 2014
Convertible Notes. We raised $878.8 from the issuance of Senior Notes and $913.3
million from various project financings. During the period, we repaid $603.9
million in project financing debt, and we used $586.9 million of proceeds from
the 2023 Convertible Senior Notes offering to repurchase the majority of the
outstanding 2006 Convertible Senior Notes that will be puttable in December 2004
and used $630.3 million to repay and repurchase various Senior Notes.
Non-Cash Activities -- See the Schedule of noncash investing and financing
activities on the Company's Consolidated Condensed Statements of Cash Flows.
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.
However, we do not currently have any significant exposures to counterparties
that are not paying on a current basis.
Letter of Credit Facilities -- At September 30, 2004 and December 31, 2003,
we had approximately $477.7 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, $243.7 million and $272.1 million in aggregate
were issued under our cash collateralized letter of credit facilities at
September 30, 2004 and December 31, 2003, respectively. At September 30, 2004,
we had $148.7 million in letters of credit outstanding under the $200 million
CalGen revolving credit agreement.
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. There were no letters of credit issued under this facility at September
30, 2004. See Note 6 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 September 30, 2004
and December 31, 2003, CES had deposited net amounts of $173.9 million and
$188.0 million, respectively, in cash as margin deposits with third parties and
had letters of credit outstanding of $3.0 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 October 2004 through December 31, 2005.
See Note 6 of the Notes to Consolidated Condensed Financial Statements for
additional information on debt obligations. We expect to incur capital
expenditures in the third and fourth quarters of 2004 of approximately $350
million, net of project financings.
During the nine months ended September 30, 2004:
Our wholly owned subsidiary CalGen, formerly 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 Senior 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 open market and privately negotiated transactions in
exchange for approximately $177.5 million in cash in the first quarter of 2004.
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 September 30, 2004,
$72.1 million aggregate principal amount of 2006 Convertible Senior Notes
remained outstanding.
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.
On September 30, 2004, we established a new $255 million Cash
Collateralized Letter of Credit Facility with Bayerische Landesbank, under which
all letters of credit previously issued under the $300 million Working Capital
Revolver and the $200 million Cash Collateralized Letter of Credit Facility will
be transitioned into that new Facility. Upon completion of this transition, all
letters of credit presently collateralized with The Bank of Nova Scotia will be
terminated.
On September 30, 2004, we closed on $785 million of 9 5/8% First-Priority
Senior Secured Notes Due 2014 ("9 5/8% Senior Notes"), offered at 99.212% of
par. The 9 5/8% Senior Notes are secured, by substantially all of the assets
owned directly by Calpine Corporation and by the stock of substantially all of
its first tier subsidiaries. Net proceeds from the 9 5/8% Senior Notes offering
were used to make open-market purchases of our existing indebtedness and any
remaining proceeds will be applied toward further open-market purchases (or
redemption) of existing indebtedness and as otherwise permitted by our
indentures.
On September 30, 2004, we closed on $736 million aggregate principal amount
at maturity of Contingent Convertible Notes Due 2014 ("2014 Convertible Notes"),
offered at 83.9% of par. The 2014 Convertible Notes will be convertible into
cash and into a variable number of shares of Calpine common stock based on a
conversion value derived from the conversion price of $3.85 per share. The
number of shares to be delivered upon conversion will be determined by the
market price of Calpine common shares at the time of conversion. The conversion
price of $3.85 per share represents a premium of approximately 23% over The New
York Stock Exchange closing price of $3.14 per Calpine common share on September
27, 2004. The 2014 Convertible Notes will pay interest at a rate of 6%, except
that in years three, four and five, in lieu of interest, the original principal
amount of $839 per note will accrete daily beginning September 30, 2006, to the
full principal amount of $1,000 per note at September 30, 2009. Upon conversion
of the 2014 Convertible Notes, we will deliver the portion of the conversion
value equal to the then current principal amount of the 2014 Convertible Notes
in cash and any additional conversion value in Calpine common stock.
Net proceeds from the 2014 Convertible Notes offering were used to redeem
our HIGH TIDES I and HIGH TIDES II preferred securities on October 20, 2004,
(see Note 15 of the Notes to Consolidated Condensed Financial Statements for
more information regarding this redemption), and to repurchase other existing
indebtedness through open-market and privately negotiated purchases, and as
otherwise permitted by our indentures.
As part of the 2014 Convertible Notes offering, we entered into a ten-year
Share Lending Agreement with Deutsche Bank AG London ("DB London"), under which
we have loaned to DB London 89 million shares of newly issued Calpine common
stock (the "loaned shares") in exchange for a loan fee of $.001 per share. The
entire 89 million shares were sold by DB London on September 30, 2004, at a
price of $2.75 per share in a registered public offering. We did not receive any
of the proceeds of the public offering. DB London is required to return the
loaned shares to us no later than the end of the ten-year term of the Share
Lending Agreement, or earlier under certain circumstances. Once loaned shares
are returned, they may not be reborrowed under the Share Lending Agreement.
Under the Share Lending Agreement, DB London is required to post and maintain
collateral in the form of cash, government securities, certificates of deposit,
high-grade commercial paper of U.S. issuers or money market shares at least
equal to 100% of the market value of the loaned shares as security for the
obligation of DB London to return the loaned shares to us.
The Company's issuance of 89 million shares of its common stock pursuant to
a the Share Lending Agreement was essentially analogous to a sale of shares
coupled with a forward contract for the reacquisition of the shares at a future
date. As there will be no cash consideration for the return of the shares, the
forward contract is considered to be prepaid. This agreement is similar to the
accelerated share repurchase transaction addressed by EITF Issue No. 99-7,
"Accounting for an Accelerated Share Repurchase Program," ("EITF Issue No.
99-7") which is characterized as two distinct transactions: a treasury stock
purchase and a forward sales contract. We have evaluated what is essentially a
prepaid forward contract under the guidance of SFAS No. 133, and determined that
the instrument meets the requirements to be accounted for in equity and is not
required to be bifurcated and accounted for separate from the Share Lending
Agreement. We recorded the transaction in equity at the fair market value of the
Calpine common stock on the date of issuance in the amount of $258.1 million
with an offsetting purchase obligation.
Under SFAS No. 150, entities that have entered into a forward contract that
requires physical settlement by repurchase of a fixed number of the issuer's
equity shares of common stock in exchange for cash shall exclude the common
shares to be redeemed or repurchased in calculating basic and diluted earnings
per share. While the Share Lending Agreement does not provide for cash
settlement, physical settlement (i.e. the 89 million shares must be returned by
the end of the agreement) is required. Further, EITF Issue No. 99-7 indicates
that the "treasury stock transaction" would result in an immediate reduction in
number of outstanding shares used to calculate basic and diluted earnings per
share. The share loan is analogous to a prepaid forward contract which would
cancel the shares issued under the Share Lending Agreement and result in an
immediate reduction in the number of outstanding shares used to calculate basic
and diluted earnings per share. Consequently, we have excluded the 89 million
shares of common stock subject to the Share Lending Agreement from the earnings
per share calculation.
See Note 6 of the Notes to Consolidated Condensed Financial Statements for
more information related to repurchases of various issuances of debt in the
third quarter of 2004.
Unrestricted Subsidiaries -- The information in this paragraph is required
to be provided under the terms of the indentures and credit agreement governing
the various tranches of our second-priority secured indebtedness (collectively,
the "Second Priority Secured Debt Instruments"). We have designated certain of
our subsidiaries as "unrestricted subsidiaries" under the Second Priority
Secured Debt Instruments. A subsidiary with "unrestricted" status thereunder
generally is not required to comply with the covenants contained therein that
are applicable to "restricted subsidiaries." The Company has designated Calpine
Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy Cogen, L.P. as
"unrestricted subsidiaries" for purposes of the Second Priority Secured Debt
Instruments. The following table sets forth selected balance sheet information
of Calpine Corporation and restricted subsidiaries and of such unrestricted
subsidiaries at September 30, 2004, and selected income statement information
for the nine months ended September 30, 2004 (in thousands):
Calpine
Corporation
And Restricted Unrestricted
Subsidiaries Subsidiaries Eliminations Total
-------------- ------------ ------------ --------------
Assets............................. $ 28,212,673 $ 440,506 $ (222,260) $ 28,430,919
============= =========== =========== =============
Liabilities........................ $ 23,165,345 $ 255,087 $ -- $ 23,420,432
============= =========== =========== =============
Total revenue......................... $ 6,890,770 $ 11,404 $ (8,468) $ 6,893,706
Total cost of revenue................. (6,465,283) (15,203) 10,186 (6,470,300)
Interest income....................... 31,126 21,453 (13,413) 39,166
Interest expense...................... (804,953) (10,404) -- (815,357)
Other................................. 271,172 (3,258) -- 267,914
------------- ----------- ----------- -------------
Net income......................... $ (77,168) $ 3,992 $ (11,695) $ (84,871)
============= ========== =========== =============
Bankruptcy-Remote Subsidiaries -- Pursuant to applicable transaction
agreements, we have established certain of our entities separate from Calpine
and our other subsidiaries. At September 30, 2004 these entities included: Rocky
Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside
Holdings, LLC, Calpine Energy Management, L.P., CES GP, LLC, Power Contracting
Finance, LLC, Power Contracting Finance III, LLC, Calpine Northbrook Energy
Marketing, LLC, Calpine Northbrook Energy Marketing Holdings, LLC, Gilroy Energy
Center, LLC, Calpine Gilroy Cogen, L.P., Calpine Gilroy I, Inc., Calpine King
City Cogen LLC, Calpine Securities Company, L.P., a parent company of Calpine
King City Cogen LLC, and Calpine King City, LLC, an indirect parent company of
Calpine Securities Company, L.P.
Indenture Compliance -- Our various indentures place conditions on our
ability to issue indebtedness, including further limitations on the issuance of
additional debt if our interest coverage ratio (as defined in the various
indentures) is below 2:1. Currently, our interest coverage ratio (as so defined)
is below 2:1 and, consequently, our indentures generally would not allow us to
issue new debt, except for (i) certain types of new indebtedness that refinances
or replaces existing indebtedness, and (ii) non-recourse debt and preferred
equity interests issued by our subsidiaries for purposes of financing certain
types of capital expenditures, including plant development, construction and
acquisition expenses. In addition, if and so long as our interest coverage ratio
is below 2:1, our indentures will limit our ability to invest in unrestricted
subsidiaries and non-subsidiary affiliates and make certain other types of
restricted payments.
Asset Sales -- On January 15, 2004, we completed the sale of our 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, we received a cash payment of $146.8 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, our undivided
interest in the Lost Pines facility was classified as "held for sale."
On September 1, 2004, we, along with Calpine Natural Gas L.P., completed
the sale of our Rocky Mountain gas reserves that were primarily concentrated in
two geographic areas: the Colorado Piceance Basin and the New Mexico San Juan
Basin. Together, these assets represent approximately 120 billion cubic feet
equivalent ("Bcfe") of proved gas reserves, producing approximately 16.3 million
net cubic feet equivalent ("MMcfe") per day of gas. Under the terms of the
agreement, we received cash payments of approximately $222.8 million, and
recorded a pre-tax gain of approximately $102.9 million. Proceeds derived from
this sale were applied as a mandatory paydown, pursuant to covenants governing
asset sales, under our First Priority Senior Secured Term Loan B Notes Due 2007
and the $300 million Working Capital Revolver.
On September 2, 2004, we completed the sale of our Canadian natural gas
reserves and petroleum assets. These Canadian assets represent approximately 221
Bcfe of proved reserves, producing approximately 61 MMcfed. Included in this
sale was our 25 percent interest in approximately 80 Bcfe of proved reserves
(net of royalties) and 32 MMcfed of production owned by the Calpine Natural Gas
Trust. Under the terms of the agreement, we received cash payments of
approximately Cdn$825.0 million, or approximately US $625 million, less
adjustments of Cdn$15.6 million, to reflect a September 2, 2004, closing date.
We recorded a pre-tax gain of approximately US$100.6 million on the sale of our
Canadian assets. A portion of the proceeds derived from this sale were applied
as a mandatory pay-down under our First Priority Senior Secured Term Loan B
Notes Due 2007 and the $300 million Working Capital Revolver, at which date the
remaining obligations under these loan facilities were fully paid down and
related letters of credit cash collateralized.
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 sale of our Canadian oil and gas
reserves (see Note 8 of the Notes to Consolidated Condensed Financial Statements
for more information on this sale) caused 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 September 30, 2004. However, because
of significant net operating loss carryforwards at September 30, 2004, we don't
expect the change in the effective tax rate to have a material impact on cash
taxes paid for 2004 or 2005.
On October 22, 2004, The American Jobs Creation Act of 2004 was signed into
law. In the nine months ended September 30, 2004, we recorded an additional tax
expense of approximately $78.8 million, which was attributable to the
repatriation of net cash proceeds from Canada to United States following the
sale of oil and gas assets in Canada. While we continue to evaluate the impact
of the provisions of The American Jobs Creation Act of 2004, we expect at this
time to be able to record a reduction of approximately $66.9 million of this tax
expense in the fourth quarter of 2004, most of which will be reflected in
discontinued operations.
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 September 30, 2004, third-party investee debt was approximately $130.1
million. Based on our pro rata ownership share of each of the investments, our
share would be approximately $45.7 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-megawatt Androscoggin
Energy Center located in Maine and has construction debt of $58.6 million
outstanding as of September 30, 2004. The debt is non-recourse to us (the "AELLC
Non-Recourse Financing"). On September 30, 2004, and December 31, 2003, our
investment balance was $15.9 million and $11.8 million, respectively, and the
carrying value of our notes receivable, including accrued but unpaid interest,
from AELLC was $23.1 million and $14.7 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, because the lending syndication had declined to extend
the date for the conversion of the construction loan to a term loan by a certain
date. AELLC has disputed the purported defaults. Also, the steam host for the
AELLC project, International Paper Company ("IP"), filed a complaint against
AELLC in October 2000, which resulted in a jury verdict of $41 million in favor
of IP on November 3, 2004. See Notes 12 and 15 of the Notes to Consolidated
Condensed Financial Statements. The litigation with IP 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.
Capital Spending -- Development and Construction
Construction and development costs in process consisted of the following at
September 30, 2004 (dollars in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP (1) CIP Costs Equipment
-------- ----------- ----------- ----------- ----------
Projects in active construction............... 10 $ 2,935,248 $ 1,057,034 $ -- $ --
Projects in advanced development.............. 11 671,594 529,475 122,769 --
Projects in suspended development............. 6 455,013 195,818 12,904 --
Projects in early development................. 2 -- -- 8,952 --
Other capital projects........................ NA 45,564 -- -- --
Unassigned equipment.......................... NA -- -- -- 66,133
----------- ----------- ----------- ---------
Total construction and development costs.... $ 4,107,419 $ 1,782,327 $ 144,625 $ 66,133
=========== =========== =========== =========
- ------------
<FN>
(1) Construction in Progress ("CIP").
</FN>
Projects in Active Construction -- The 10 projects in active construction
are estimated to come on line from February 2005 to November 2007. These
projects will bring on line approximately 4,634 MW of base load capacity (5,244
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. One additional project, Goldendale, totaling 237 MW (271 MW with
peaking capacity) that was in active construction at the beginning of the
quarter went on line during the quarter. At September 30, 2004, the estimated
funding requirements to complete these 10 projects, net of expected project
financing proceeds, is approximately $0.4 billion.
Projects in Advanced Development -- There are 11 projects in advanced
development. These projects will bring on line approximately 5,585 MW of base
load capacity (6,651 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 September 30, 2004, the estimated cost to complete the 11
projects in advanced development is approximately $3.7 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 3,458 MW of base load capacity (3,938 MW with peaking
capacity). At September 30, 2004, the estimated cost to complete the six
projects is approximately $2.1 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 September 30, 2004, we had made progress
payments on four turbines, one heat recovery steam generator, and other
equipment with an aggregate carrying value of $66.1 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 projects including those in construction and
development 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. 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.
Risk Factor
The following risk factor is listed as an addition to those disclosed in
our Annual Report on Form 10-K/A, amendment 2.
While we believe that we currently have adequate internal control
procedures in place, we are still exposed to potential risks resulting from
recent legislation requiring companies to evaluate controls under Section 404 of
the Sarbanes-Oxley Act of 2002.
We are evaluating our internal controls systems in order to allow
management to report on, and our Registered Independent Public Accountants to
attest to, our internal controls as required by Section 404 of the
Sarbanes-Oxley Act. We are performing the system and process evaluation and
testing (and any necessary remediation) required in an effort to comply with the
management certification and auditor attestation requirements of Section 404. As
a result, we are expending significant management and employee time and
resources and incurring significant additional expense. While we have discovered
a number of deficiencies to date that have required or will require remediation,
we believe that we currently have adequate internal controls and that there are
no remaining deficiencies that, individually or in the aggregate, constitute
material weaknesses While we anticipate being able to fully implement the
requirements relating to internal controls and all other aspects of Section 404
in a timely fashion, we cannot be certain as to the timing of completion of our
evaluation, testing and remediation actions or the impact of the same on our
operations since there is no precedent available by which to measure compliance
adequacy. If we are not able to implement the requirements of Section 404 in a
timely manner, including completing our assessment by the filing deadline, our
auditors might be required to disclaim an opinion on internal controls and
investor confidence in our internal controls over financial reporting may be
adversely effected.
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 megawatt hours ("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 L.P., 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. For
comparison purposes we also include POX per actual MWh.
The table below presents, the operating performance metrics discussed
above.
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- --------------------------------
2004 2003 2004 2003
-------------- ---------------- -------------- ---------------
(In thousands)
Operating Performance Metrics:
Total deliveries of power:
MWh generated........................................... 29,390 25,449 72,522 62,069
HBO and trading MWh sold................................ 25,458 22,718 65,941 60,886
------------- -------------- ------------- -------------
MWh delivered........................................... 54,848 48,167 138,463 122,955
============= ============== ============= =============
Average availability...................................... 97% 98% 93% 91%
Average baseload capacity factor:
Average total MW in operation........................... 26,192 21,549 24,108 19,637
Less: Average MW of pure peakers........................ 2,951 2,889 2,951 2,599
------------- -------------- ------------- -------------
Average baseload MW in operation........................ 23,241 18,660 21,157 17,038
Hours in the period..................................... 2,208 2,208 6,576 6,552
Potential baseload generation (MWh)..................... 51,316 41,201 139,128 111,633
Actual total generation (MWh)........................... 29,390 25,449 72,522 62,069
Less: Actual pure peakers' generation (MWh)............. 557 762 1,130 1,073
------------- -------------- ------------- -------------
Actual baseload generation (MWh)........................ 28,883 24,687 71,392 60,996
Average baseload capacity factor........................ 56% 60% 51% 55%
Average heat rate for gas-fired power plants
(excluding peakers) (Btu's/KWh):
Not steam adjusted...................................... 8,115 7,827 8,177 7,924
Steam adjusted.......................................... 7,140 7,159 7,152 7,202
Average all-in realized electric price:
Electricity and steam revenue........................... $ 1,671,147 $ 1,416,866 $ 4,230,004 $ 3,563,193
Spread on sales of purchased power for hedging and
optimization........................................... 79,424 7,121 135,996 14,542
------------- -------------- ------------- -------------
Adjusted electricity and steam revenue (in thousands)... $ 1,750,571 $ 1,423,987 $ 4,366,000 $ 3,577,735
MWh generated (in thousands)............................ 29,390 25,449 72,522 62,069
Average all-in realized electric price per MWh.......... $ 59.56 $ 55.95 $ 60.20 $ 57.64
Average cost of natural gas:
Cost of oil and natural gas burned by power plants
(in thousands)......................................... $ 1,103,290 $ 794,134 $ 2,768,910 $ 2,014,945
Fuel cost elimination................................... 45,833 63,520 157,738 228,669
------------- -------------- ------------- -------------
Adjusted fuel expense................................... $ 1,149,123 $ 857,654 $ 2,926,648 $ 2,243,614
Million Btu's ("MMBtu") of fuel consumed by generating
plants (in thousands).................................. 199,812 169,586 505,444 414,944
Average cost of natural gas per MMBtu................... $ 5.75 $ 5.06 $ 5.79 $ 5.41
MWh generated (in thousands)............................ 29,390 25,449 72,522 62,069
Average cost of adjusted fuel expense per MWh........... $ 39.10 $ 33.70 $ 40.35 $ 36.15
Average spark spread:
Adjusted electricity and steam revenue (in thousands)... $ 1,750,571 $ 1,423,987 $ 4,366,000 $ 3,577,735
Less: Adjusted fuel expense (in thousands).............. 1,149,123 857,654 2,926,648 2,243,614
------------- -------------- ------------- -------------
Spark spread (in thousands)............................. $ 601,448 $ 566,333 $ 1,439,352 $ 1,334,121
MWh generated (in thousands)............................ 29,390 25,449 72,522 62,069
Average spark spread per MWh............................ $ 20.46 $ 22.25 $ 19.85 $ 21.49
Add: Equity gas contribution(1)......................... $ 27,554 $ 41,407 $ 97,555 $ 149,585
Spark spread with equity gas benefits (in thousands).... $ 629,002 $ 607,740 $ 1,536,907 $ 1,483,706
Average spark spread with equity gas benefits per MWh... $ 21.40 $ 23.88 $ 21.19 $ 23.90
Average plant operating expense ("POX") per normalized MWh
(We also show POX per actual MWh for comparison):
Average total consolidated MW in operations............... 26,192 21,549 24,108 19,637
Hours in the period..................................... 2,208 2,208 6,576 6,552
Total potential MWh..................................... 57,832 47,580 158,534 129,133
Normalized MWh (at 70% capacity factor)................. 40,482 33,306 110,974 90,393
Plant operating expense (POX)........................... $ 176,333 $ 174,545 $ 575,830 $ 496,119
POX per normalized MWh.................................. $ 4.36 $ 5.24 $ 5.19 $ 5.49
POX per actual MWh...................................... $ 6.00 $ 6.86 $ 7.94 $ 7.99
- ------------
<FN>
(1) Equity gas contribution margin:
</FN>
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- --------------------------------
2004 2003 2004 2003
-------------- ---------------- -------------- ---------------
(In thousands)
Oil and gas sales........................................... $ 17,687 $ 16,578 $ 47,472 $ 45,394
Add: Fuel cost eliminated in consolidation.................. 45,833 63,520 157,738 228,669
------------- -------------- ------------- -------------
Subtotal.................................................. $ 63,520 $ 80,098 $ 205,210 $ 274,063
Less: Oil and gas operating expense......................... 14,719 15,262 42,864 53,642
Less: Depletion, depreciation and amortization.............. 21,247 23,429 64,791 70,836
------------- -------------- ------------- -------------
Equity gas contribution margin.............................. $ 27,554 41,407 $ 97,555 149,585
MWh generated (in thousands)................................ 29,390 25,449 72,522 62,069
Equity gas contribution margin per MWh...................... $ 0.94 $ 1.63 $ 1.35 $ 2.41
The table below provides additional detail of total mark-to-market activity.
For the three and nine months ended September 30, 2004 and 2003, mark-to-market
activity, net consisted of (dollars in thousands):
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- --------------------------------
2004 2003 2004 2003
-------------- ---------------- -------------- ---------------
(In thousands)
Realized:
Power activity
"Trading Activity" as defined in EITF No. 02-03......... $ 9,412 $ 8,581 $ 39,258 $ 33,243
Other mark-to-market activity(1)........................ (434) (8,935) (6,378) (8,935)
------------- -------------- ------------- -------------
Total realized power activity.......................... $ 8,978 $ (354) $ 32,880 $ 24,308
============= ============== ============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03......... $ 9,679 $ 261 $ 9,548 $ 5,872
Other mark-to-market activity(1)........................ -- -- -- --
------------- -------------- -------------- -------------
Total realized gas activity............................ $ 9,679 $ 261 $ 9,548 $ 5,872
============= ============== ============= =============
Total realized activity:
"Trading Activity" as defined in EITF No. 02-03......... $ 19,091 $ 8,842 $ 48,806 $ 39,115
Other mark-to-market activity(1)........................ (434) (8,935) (6,378) (8,935)
------------- -------------- ------------- -------------
Total realized activity................................ $ 18,657 $ (93) $ 42,428 $ 30,180
============= ============== ============= =============
Unrealized:
Power activity
"Trading Activity" as defined in EITF No. 02-03......... $ (16,934) $ (15,920) $ (40,803) $ (29,031)
Ineffectiveness related to cash flow hedges............. 1,142 (115) 1,268 (4,753)
Other mark-to-market activity(1)........................ (240) (1,087) (13,015) (1,087)
------------- -------------- ------------- -------------
Total unrealized power activity........................ $ (16,032) $ (17,122) $ (52,550) $ (34,871)
============= ============== ============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03......... $ (8,508) $ 10,562 $ (11,610) $ 12,140
Ineffectiveness related to cash flow hedges............. 777 (4,370) 6,540 3,810
Other mark-to-market activity(1)........................ -- -- -- --
------------- -------------- ------------- -------------
Total unrealized gas activity.......................... $ (7,731) $ 6,192 $ (5,070) $ 15,950
============= ============== ============= =============
Total unrealized activity:
"Trading Activity" as defined in EITF No. 02-03........... $ (25,442) $ (5,358) $ (52,413) $ (16,891)
Ineffectiveness related to cash flow hedges............... 1,919 (4,485) 7,808 (943)
Other mark-to-market activity(1).......................... (240) (1,087) (13,015) (1,087)
------------- -------------- ------------- -------------
Total unrealized activity.............................. $ (23,763) $ (10,930) (57,620) $ (18,921)
============= ============== ============= =============
Total mark-to-market activity:
"Trading Activity" as defined in EITF No. 02-03........... $ (6,351) $ 3,484 $ (3,607) $ 22,224
Ineffectiveness related to cash flow hedges............... 1,919 (4,485) 7,808 (943)
Other mark-to-market activity(1).......................... (674) (10,022) (19,393) (10,022)
------------- -------------- ------------- -------------
Total mark-to-market activity.......................... $ (5,106) $ (11,023) $ (15,192) $ 11,259
============= ============== ============= =============
- ------------
<FN>
(1) Activity related to our assets but does not qualify for hedge accounting.
</FN>
Overview
Summary of Key Activities
Finance - New Issuances
Date Amount Description
- ---------- ---------------- ------------------------------------------------
8/05/04 $250.0 million CEM entered into a letter of credit facility
with Deutsche Bank that expires October 2005
9/30/04 $785.0 million Received funding on offering of 9 5/8% First
Priority Senior Secured Notes due 2014,
offered at 99.212% of par
9/30/04 $736.0 million Received funding on offering of Contingent
Convertible Notes due 2014, offered at 83.9%
of par
9/30/04 $255.0 million Established a new Cash Collateralized Letter of
Credit Facility with Bayerische Landesbank
Finance - Repurchases/Retirements
Date Amount Description
- ---------- ---------------- ------------------------------------
7/1/04 $20.0 million Exchanged 4.2 million Calpine common shares
in privately negotiated transactions for
approximately $20.0 million of par value of
7/04 HIGH TIDES I - 9/04 $734.8 million Repurchased
$734.8 million in principal amount of
outstanding Senior Notes, 2023 Convertible
Senior Notes, and HIGH TIDES III in exchange
for $553.8 million in cash.
Other:
Date Description
- ---------- -------------------------------------------------------------------
7/27/04 Entered into a five year agreement with Snapping Shoals EMC for
200 megawatts of capacity and energy
8/3/04 Signed a ten year power sales commitment with Wisconsin Public
Service for 235 megawatts of capacity, energy and ancillary
services, subject to approval by the Public Service Commission of
Wisconsin
9/1/04 Completed sale of natural gas reserves in the Colorado Piceance
Basin and New Mexico San Juan Basin for approximately $223
million
9/2/04 Completed sale of all Canadian natural gas reserves and petroleum
assets for approximately Cdn$825 million (US$625 million)
9/30/04 Entered into a ten-year Share Lending Agreement, loaning 89 million
shares of newly issued Calpine common stock to Deutsche Bank AG
London
Power Plant Development and Construction:
Date Project Description
- ---------- ------------------------ --------------------
9/17/04 Goldendale Energy Center Commercial Operation
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
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 FERC
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 resulted in a FERC order issued on March
26, 2004, 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.
State of California, Ex. Rel. Bill Lockyer, Attorney General v. Federal
Energy Regulatory Commission. On September 9, 2004, the Ninth Circuit Court of
Appeals issued a decision on appeal of a Petition for Review of an order issued
by FERC in FERC Docket No. EL02-71 wherein the Attorney General had filed a
complaint (the "AG Complaint") under Sections 205 and 206 of the Federal Power
Act (the "Act") alleging that parties who misreported or did not properly report
market based transactions were in violation of their market based rate tariff
and as a result were not accorded protection under section 206 of the Act from
retroactive refund liability. The Ninth Circuit remanded the order to FERC for
rehearing. FERC is required to determine whether refunds should be required for
violation of reporting requirements prior to October 2, 2000. The proceeding on
remand has not yet been established. In connection with its settlement agreement
with various State of California entities (including the Attorney General),
Calpine and its affiliates settled all claims related to the AG Complaint.
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. 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.
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.
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 September 30, 2004, is summarized in the table
below (in thousands):
Fair value of contracts outstanding at January 1, 2004............ $ 76,541
Cash losses recognized or otherwise settled during
the period(1)................................................... 10,057
Non-cash losses recognized or otherwise settled during
the period(2)................................................... (27,152)
Changes in fair value attributable to new contracts............... 5,515
Changes in fair value attributable to price movements............. (122,443)
-----------
Fair value of contracts outstanding at September 30, 2004(3).. $ (57,482)
===========
Realized cash flow from fair value hedges(4)...................... $ 109,544
- ----------
(1) Recognized losses from commodity cash flow hedges of $(61.2) million
(represents realized value of cash flow hedge activity of $(46.5) million
as disclosed in Note 9 of the Notes to Consolidated Condensed Financial
Statements, net of non-cash OCI items relating to terminated derivatives of
$7.0 million and equity method hedges of $7.7 million) and realized gains
of $51.2 million on mark-to-market activity, (represents realized value of
mark-to-market activity of $42.4 million, as reported in the Consolidated
Condensed Statements of Operations under mark-to-market activities, net of
$(8.8) million of non-cash realized mark-to-market activity).
(2) This represents the non-cash amortization of deferred items embedded in our
derivative assets and liabilities.
(3) Net commodity derivative assets reported in Note 9 of the Notes to
Consolidated Condensed Financial Statements.
(4) Not included as part of the roll-forward of net derivative assets and
liabilities because changes in the hedge instrument and hedged item move in
equal and offsetting directions to the extent the fair value hedges are
perfectly effective.
The fair value of outstanding derivative commodity instruments at September
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................................ $ 41,653 $ 155,268 $ -- $ -- $ 196,921
Prices provided by other external sources............. (44,204) (173,840) 5,720 (16,533) (228,857)
Prices based on models and other valuation methods.... -- 1,709 2,834 (30,089) (25,546)
---------- ---------- -------- --------- ----------
Total fair value.................................... $ (2,551) $ (16,863) $ 8,554 $ (46,622) $ (57,482)
========== ========== ======== ========= ==========
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 September 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 September 30, 2004)
Investment grade...................................... $ (3,621) $ (28,912) $ 8,936 $ (46,622) $ (70,219)
Non-investment grade.................................. 2,200 13,261 -- -- 15,461
No external ratings................................... (1,130) (1,212) (382) -- (2,724)
---------- ---------- -------- --------- --=-------
Total fair value.................................... $ (2,551) $ (16,863) $ 8,554 $ (46,622) $ (57,482)
========== ========== ======== ========= ==========
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 September 30, 2004:
Electricity.............. $ (249,717) $ (573,224)
Natural gas.............. 192,235 170,134
------------ -------------
Total.................. $ (57,482) $ (403,090)
============ =============
Derivative commodity instruments included in the table are those included
in Note 9 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 decreased 24%
from December 31, 2003, to September 30, 2004, while the total volume of open
power derivative positions increased 46% 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 September 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
nine months ended September 30, 2004, have reflected this. See Notes 9 and 10 of
the Notes to Consolidated Condensed Financial Statements for additional
information on derivative activity and OCI, respectively.
Available-for-Sale Debt Securities -- Through September 30, 2004, we have
exchanged 30.8 million Calpine common shares in privately negotiated
transactions for approximately $152.5 million par value of HIGH TIDES I and HIGH
TIDES II. We have also repurchased $115.0 million par value of HIGH TIDES III.
At September 30, 2004, the repurchased HIGH TIDES are classified as
available-for-sale and recorded at fair market value. HIGH TIDES I and II are
recorded in Other Current Assets and HIGH TIDES III in Other Assets. See Note 15
of the Notes to Consolidated Condensed Financial Statements for more information
on the redemption of HIGH TIDES I and II subsequent to September 30, 2004. The
following tables present our different classes of debt securities held by
expected maturity date and fair market value as of September 30, 2004, (dollars
in thousands):
Weighted
Average
Interest
Rate 2004 2005 2006 2007 2008 Thereafter Total
-------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
HIGH TIDES I........... 5.75% $ 77,500 $ -- $ -- $ -- $ -- $ -- $ 77,500
HIGH TIDES II.......... 5.50% 75,000 -- -- -- -- -- 75,000
HIGH TIDES III......... 5.00% -- -- -- -- -- 115,000 115,000
===== ---------- ---------- ---------- ---------- ---------- --------- ----------
Total............... $ 152,500 $ -- $ -- $ -- $ -- $ 115,000 $ 267,500
========== ========== ========== ========== ========== ========= ==========
Fair
Market
Value
-----------
HIGH TIDES I...................... $ 77,500
HIGH TIDES II..................... 75,000
HIGH TIDES III.................... 110,400
-----------
Total........................... $ 262,900
===========
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 September 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 (2,488)
2011.......... 291,897 4.5% 3-month US $LIBOR (12,547)
2011.......... 209,833 4.4% 3-month US $LIBOR (7,589)
2011.......... 41,822 4.4% 3-month US $LIBOR (1,513)
2011.......... 39,612 6.9% 3-month US $LIBOR (4,716)
2012.......... 107,226 6.5% 3-month US $LIBOR (13,206)
2016.......... 21,330 7.3% 3-month US $LIBOR (3,951)
2016.......... 14,220 7.3% 3-month US $LIBOR (2,635)
2016.......... 42,660 7.3% 3-month US $LIBOR (7,904)
2016.......... 28,440 7.3% 3-month US $LIBOR (5,269)
2016.......... 35,550 7.3% 3-month US $LIBOR (6,587)
----------- --- -----------
Total....... $ 890,768 5.2% $ (68,405)
=========== === ===========
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% $ (5,252)
2011.......... 100,000 6-month US $LIBOR 8.5% (3,549)
2011.......... 200,000 6-month US $LIBOR 8.5% (7,437)
2011.......... 100,000 6-month US $LIBOR 8.5% (6,353)
----------- --- -----------
Total....... $ 500,000 8.5% $ (22,591)
=========== === ===========
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 September 30, 2004 Adverse Interest Rate Change
- ----------------------------------- ----------------------------
$ (68,405) $ (118,545)
Fixed to Variable Swaps
Fair Value After a
1.0% (100 basis point)
Fair Value as of September 30, 2004 Adverse Interest Rate Change
- ----------------------------------- ----------------------------
$ (22,591) $ (49,925)
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 September 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 $ (22,349)
$Cdn-$US (12,357)
$Cdn-Euro (1,512)
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.
Foreign Currency Transaction Gain (Loss)
ThreeMonths Ended September 30, 2004, Compared to Three Months Ended
September 30, 2003:
The major components of our foreign currency transaction loss of $(12.4)
million and our foreign currency transaction gain of $8.1 million for the
three months ended September 30, 2004 and 2003, respectively, are as
follows (amounts in millions):
2004 2003
------ ------
Gain (Loss) from $Cdn-$US fluctuations:............... $(7.4) $9.3
Gain (Loss) from GBP-Euro fluctuations:............... (4.1) (2.1)
Gain (Loss) from other currency fluctuations:......... (0.9) 0.8
On September 3, 2004, in conjunction with the sale of our Canadian gas
assets, our Canadian subsidiary distributed a portion of the sales proceeds to
the U.S. parent company, which effectively reduced the size of our investment in
our Canadian dollar denominated subsidiaries. As a result, the degree to which
we could designate our $Cdn-denominated liabilities as hedges against our
investment in Canadian dollar denominated subsidiaries was reduced, creating
additional $Cdn-$US exposure. Following the September 2, 2004, sale, the
Canadian dollar strengthened considerably against the U.S. dollar, creating
re-measurement losses on this exposure.
The significant $Cdn-$US gain for the three months ended September 30,
2003, was driven primarily by the interest receivable on a large intercompany
loan between a Calpine U.S. entity and a Calpine Canadian entity, denominated in
Canadian dollars. The underlying loan is deemed to be a permanent investment,
but the associated interest is generally settled between the two entities on a
recurring basis, thereby requiring any re-measurement gains or losses to be
recorded as a component of income.
During the three months ended September 30, 2004 and 2003, respectively,
the Euro strengthened against the GBP, triggering re-measurement losses
associated with our Euro-denominated 8 3/8% Senior Notes Due 2008. These Senior
Notes were issued by a Calpine subsidiary whose functional currency is GBP. As a
result, when the Euro strengthened, the underlying debt was re-measured at a
higher GBP value than in previous periods. The increase of the liability in GBP
resulted in a foreign currency transaction loss under SFAS No. 52.
Nine Months Ended September 30, 2004, Compared to Nine Months Ended
September 30, 2003:
The major components of our foreign currency transaction losses of $7.5
million and $36.2 million, respectively, for the nine months ended
September 30, 2004 and 2003, respectively, are as follows (amounts in
millions):
2004 2003
------- -------
Gain (Loss) from $Cdn-$US fluctuations:............... $(13.1) $(25.6)
Gain (Loss) from GBP-Euro fluctuations:............... 6.5 (11.4)
Gain (Loss) from other currency fluctuations:......... (0.9) 0.8
The $Cdn-$US loss for the nine months ended September 30, 2004, was driven
by two factors. First, we recognized re-measurement losses on the translation of
the interest receivable associated with our large intercompany loan that has
been deemed a permanent investment during the first two quarters of 2004, as the
Canadian dollar weakened against the U.S. dollar. Second, we recognized
re-measurement losses during the third quarter of 2004 when the Canadian dollar
strengthened after the sale of our Canadian gas assets and subsequent
repatriation of a portion of the sales proceeds to the U.S. parent company
reduced the degree to which we could designate our $Cdn-denominated liabilities
as hedges against our investment in Canadian dollar denominated subsidiaries.
The $Cdn-$US loss for the nine months ended September 30, 2003, was driven
primarily by a significant strengthening of the Canadian dollar against the U.S.
dollar during the first six months of 2003, at a time when the majority of our
$Cdn-$US payable exposures were not designated as hedges of the net investment
in our Canadian operations. The losses on these loans were partially offset by
re-measurement gains recognized on the translation of the interest receivable
associated with our large intercompany loan that has been deemed a permanent
investment.
During the nine months ended September 30, 2004, the Euro weakened against
the GBP, triggering re-measurement gains associated with our Euro-denominated 8
3/8% Senior Notes Due 2008.
During the nine months ended September 30, 2003, the Euro strengthened
against the GBP, triggering re-measurement losses associated with these Senior
Notes.
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. New borrowings under our $200 million CalGen revolving
credit agreement is used exclusively to fund the construction of the CalGen
power plants still in construction. 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.
The following table summarizes our variable-rate debt exposed to interest
rate risk as of September 30, 2004. All outstanding balances and fair market
values are shown net of applicable premium or discount, if any (dollars in
thousands):
2004(8) 2005 2006 2007 2008
------- ------- ------- ---------- -------
3-month US $LIBOR weighted average interest rate basis (4)
MEP Pleasant Hill Term Loan, Tranche A ............................. $1,138 $ 6,700 $ 7,482 $ 8,132 $ 9,271
------ ------- ------- ---------- -------
Total of 3-month US $LIBOR rate debt ............................. 1,138 6,700 7,482 8,132 9,271
1-month EURLIBOR weighted average interest rate basis (4)
Thomassen revolving line of credit ................................. -- 3,298 -- -- --
------ ------- ------- ---------- -------
Total of 1-month EURLIBOR rate debt .............................. -- 3,298 -- -- --
1-month US $LIBOR weighted average interest rate basis (4)
First Priority Secured Floating Rate Notes Due 2009 (CalGen) ....... -- -- -- 1,175 2,350
CalGen Revolver .................................................... -- -- -- 36,500 --
------ ------- ------- ---------- -------
Total of 1-month US $LIBOR rate debt ............................. -- -- -- 37,675 2,350
6-month US $LIBOR weighted average interest rate basis (4)
Third Priority Secured Floating Rate Notes Due 2011 (CalGen) ....... -- -- -- -- --
------ ------- ------- ---------- -------
Total of 6-month US $LIBOR rate debt ............................. -- -- -- -- --
5-month US $LIBOR weighted average interest rate basis (4)
Riverside Energy Center project financing .......................... -- 3,685 3,685 3,685 3,685
Rocky Mountain Energy Center project financing ..................... -- 2,649 2,649 2,649 2,649
------ ------- ------- ---------- -------
Total of 6-month US $LIBOR rate debt ............................. -- 6,334 6,334 6,334 6,334
(1)(4)
First Priority Secured Institutional Term Loan Due 2009 (CCFC I) ... -- 3,208 3,208 3,208 3,208
Second Priority Senior Secured Floating Rate Notes Due 2011
(CCFC I) .......................................................... -- -- -- -- --
------ ------- ------- ---------- -------
Total of variable rate debt as defined at (1) below .............. -- 3,208 3,208 3,208 3,208
(2)(4)
Second Priority Senior Secured Term Loan B Notes Due 2007 .......... 1,875 7,500 7,500 725,625 --
------ ------- ------- ---------- -------
Total of variable rate debt as defined at (2) below .............. 1,875 7,500 7,500 725,625 --
(3)(4)
Second Priority Senior Secured Floating Due 2007 ................... 1,250 5,000 5,000 483,750 --
Blue Spruce Energy Center project financing ........................ -- 1,875 3,750 3,750 3,750
------ ------- ------- ---------- -------
Total of variable rate debt as defined at (3) below .............. 1,250 6,875 8,750 487,500 3,750
(5)(4)
First Priority Secured Term Loans Due 2009 (CalGen) ............... -- -- -- 3,000 6,000
Second Priority Secured Floating Rate Notes Due 2010 (CalGen) ..... -- -- -- -- 3,200
Second Priority Secured Term Loans Due 2010 (CalGen) .............. -- -- -- -- 500
------ ------- ------- ---------- -------
Total of variable rate debt as defined at (5) below ............. -- -- -- 3,000 9,700
------ ------- ------- ---------- -------
(6)(4)
Island Cogen ....................................................... -- 6,294 -- -- --
------ ------- ------- ---------- -------
Total of variable rate debt as defined at (6) below .............. -- 6,294 -- -- --
------
(6)(4)
Contra Costa ....................................................... -- 168 175 182 190
------ ------- ------- ---------- -------
Total of variable rate debt as defined at (6) below .............. -- 168 175 182 190
------ ------- ------- ---------- -------
Grand total variable-rate debt instruments ...................... $4,263 $40,377 $33,449 $1,271,656 $34,803
------ ======= ======= ========== =======
Fair Value
Thereafter 9/30/2004(9)
---------- ------------
3-month US $LIBOR weighted average interest rate basis (4)
MEP Pleasant Hill Term Loan, Tranche A ............................. $ 95,235 $ 127,958
---------- -----------
Total of 3-month US $LIBOR rate debt ............................. 95,235 127,958
1-month EURLIBOR weighted average interest rate basis (4)
Thomassen revolving line of credit ................................. -- 3,298
---------- -----------
Total of 1-month EURLIBOR rate debt .............................. -- 3,298
1-month US $LIBOR weighted average interest rate basis (4)
First Priority Secured Floating Rate Notes Due 2009 (CalGen) ....... 231,475 235,000
CalGen Revolver .................................................... -- 36,500
---------- -----------
Total of 1-month US $LIBOR rate debt ............................. 231,475 271,500
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 .......................... 353,760 368,500
Rocky Mountain Energy Center project financing ..................... 254,304 264,900
---------- -----------
Total of 6-month US $LIBOR rate debt ............................. 608,064 633,400
(1)(4)
First Priority Secured Institutional Term Loan Due 2009 (CCFC I) ... 365,189 378,021
Second Priority Senior Secured Floating Rate Notes Due 2011
(CCFC I) .......................................................... 408,326 408,326
---------- -----------
Total of variable rate debt as defined at (1) below .............. 773,515 786,347
(2)(4)
Second Priority Senior Secured Term Loan B Notes Due 2007 .......... -- 742,500
---------- -----------
Total of variable rate debt as defined at (2) below .............. -- 742,500
(3)(4)
Second Priority Senior Secured Floating Due 2007 ................... -- 495,000
Blue Spruce Energy Center project financing ........................ 106,675 119,800
---------- -----------
Total of variable rate debt as defined at (3) below .............. 106,675 614,800
(5)(4)
First Priority Secured Term Loans Due 2009 (CalGen) ............... 591,000 600,000
Second Priority Secured Floating Rate Notes Due 2010 (CalGen) ..... 628,039 631,239
Second Priority Secured Term Loans Due 2010 (CalGen) .............. 98,131 98,631
---------- -----------
Total of variable rate debt as defined at (5) below ............. 1,317,170 1,329,870
---------- -----------
(6)(4)
Island Cogen ....................................................... -- 6,294
---------- -----------
Total of variable rate debt as defined at (6) below .............. -- 6,294
(6)(4)
Contra Costa ....................................................... 1,561 2,276
---------- -----------
Total of variable rate debt as defined at (6) below .............. 1,561 2,276
---------- -----------
Grand total variable-rate debt instruments ...................... $3,813,695 $ 5,198,243
========== ===========
- ------------
<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 3 months remaining in 2004. (9) Fair value equals carrying value.
</FN>
New Accounting Pronouncements
EITF 04-7
An integral part of applying FIN 46-R is determining which economic
interests are variable interests. In order for an interest to be considered a
variable interest, it must "absorb variability" of changes in the fair value of
the VIE's underlying net assets. Questions have arisen regarding (a) how to
determine whether an interest absorbs variability , and (b) whether the nature
of how a long position is created, either synthetically through derivative
transactions or through cash transactions, should affect the assessment of
whether an interest is a variable interest. EITF Issue No. 04-7 : "Determining
Whether an Interest Is a Variable Interest in a Potential Variable Interest
Entity" ("EITF Issue No. 04-7") is still in the discussion phase, but will
eventually provide a model to assist in determining whether an economic interest
in a VIE is a variable interest. The Task Force's discussions on this Issue have
centered around whether the variability should be based on whether (a) the
interest absorbs fair value variability, (b) the interest absorbs cash flow
variability, or (c) the interest absorbs both fair value and cash flow
variability. The final conclusions reached on this issue may impact the
Company's methodology used in making quantitative assessments of the variability
of: the Company's joint venture investments: wholly owned subsidiaries that have
issued preferred interests to third parties; wholly owned subsidiaries that have
entered into operating leases of power plants that contain a fixed price
purchase option; wholly owned subsidiaries that have entered into longer term
power sales agreements with third parties; and the Company's investments in
SPEs. However, until the EITF reaches a final consensus, the effects of this
issue on the Company's financial statements is indeterminable.
EITF 04-8
On September 30, 2004, the EITF reached a final consensus on EITF Issue No.
04-8 ("EITF Issue No. 04-8"): "The Effect of Contingently Convertible Debt on
Diluted Earnings per Share." The guidance in EITF Issue No. 04-8 is effective
for periods ending after December 15, 2004, and must be applied by retroactively
restating previously reported earnings per shares. The consensus requires
companies that have issued contingently convertible instruments with a market
price trigger to include the effects of the conversion in diluted earnings per
share, regardless of whether the price trigger had been met. Prior to this
consensus, contingently convertible instruments were not included in diluted
earnings per share if the price trigger had not been met. Typically, the
affected instruments are convertible into common stock of the issuer after the
issuer's common stock price has exceeded a predetermined threshold for a
specified time period. Our $634 million outstanding at September 30, 2004, of
4.75% Contingent Convertible Senior Notes Due 2023 ("2023 Convertible Senior
Notes") and $736 million aggregate principal amount at maturity of Contingent
Convertible Notes Due 2014 ("2014 Convertible Notes") will be affected by the
new guidance. This new guidance will accelerate the point at which the 2023
Convertible Senior Notes and the 2014 Convertible Notes would potentially impact
diluted earnings per share, but once the trigger price is exceeded, there would
be no additional dilution.
SFAS No. 128-R
FASB is expected to modify Statement of Financial Accounting Standards No.
128: Earnings Per Share ("SFAS No. 128") to make it consistent with
International Accounting Standard No. 33, Earnings Per Share so earnings per
share computations will be comparable on a global basis. The effective date is
anticipated to coincide with the effective date of EITF Issue No. 04-8. The
proposed changes will affect the application of the treasury stock method and
contingently issuable (based on conditions other than market price) share
guidance for computing year-to-date diluted earnings per share. In addition to
modifying the year-to-date calculation mechanics, the proposed revision to SFAS
No. 128 would eliminate a company's ability to overcome the presumption of share
settlement for those instruments or contracts that can be settled, at the issuer
or holder's option, in cash or shares. Under the revised guidance, the FASB has
indicated that any possibility of share settlement other than in an event of
bankruptcy will require an assumption of share settlement when calculating
diluted earnings per share. Our 2023 Convertible Senior Notes and 2014
Convertible Notes contain provisions that would require share settlement in the
event of conversion, during certain limited events of default, including
bankruptcy. Additionally, the 2023 Convertible Senior Notes include a provision
allowing us to meet a put with either cash or shares of stock. The revised
guidance is expected to increase the potential dilution to our earnings per
share, particularly when the price of our common stock is low, since the more
dilutive of the calculations would be used considering both: (i) normal
conversion assuming a combination of cash and a variable number of shares; and
(ii) conversion during certain limited events of default assuming 100% shares at
the fixed conversion rate.
Summary of Dilution Potential of Our Contingent Convertible Notes: 2023
Convertible Senior Notes and 2014 Convertible Notes
The table below assumes normal conversion for the 2014 Convertible Notes
and the 2023 Convertible Senior Notes in which the principal amount is paid in
cash, and the excess up to the conversion value is paid in shares of Calpine
common stock. The table shows only the potential impact of our two contingent
convertible notes issuances and does not include the potential dilutive effect
of HIGH TIDES III, the remaining 4% Convertible Senior Notes Due 2006 that can
be put to the Company in December 2004 or employee stock options. Additionally,
we are still assessing the potential impact of the SFAS No. 128-R exposure draft
on our convertible issues. See Note 2 of the Notes to Consolidated Condensed
Financial Statements for more information.
2023
2014 Convertible
Convertible Senior
Notes Notes
Size of issuance............................... $736,000,000 $ 633,775,000
Conversion price per share..................... $3.85 $6.50
Conversion rate................................ 259.7403 153.8462
Trigger price (20% over conversion price)...... $4.62 $7.80
Additional Shares
2023
Future Calpine 2014 Convertible Earnings
Common Stock Convertible Senior Share per Diluted
Price Notes* Notes Subtotal Share Increase Share
- -------------------------------- ------------ ------------ ------------ -------------- -----------
$5.00 43,968,831 NA 43,968,831 9.9% 9.0%
$7.50 93,035,498 13,000,542 106,036,040 23.8% 19.2%
$10.00 117,568,831 34,126,375 151,695,207 34.1% 25.4%
$20.00 154,368,831 65,815,125 220,183,957 49.5% 33.1%
$100.00 183,808,831 91,166,125 274,974,957 61.8% 38.2%
Basic earnings per share base at
September 30, 2004............ 445,092,147
<FN>
* In the case of the 2014 Convertible Notes, since the conversion value is
set for any given common stock price, more shares would be issued when the
accreted value is less than $1,000 than in the table above since the accreted
value (initially $839 per bond) is paid in cash, and the balance of the
conversion value is paid in shares. The incremental shares assuming conversion
when the accreted value is only $839 per bond are shown in the table below:
</FN>
Future Calpine
Common Stock Incremental
Price Shares
- -------------------------------- -----------
$5.00 23,719,200
$7.50 15,799,467
$10.00 11,849,600
$20.00 5,924,800
$100.00 1,184,960
EITF 03-13
At the September 29, 2004, EITF meeting, the EITF reached a tentative
conclusion on Issue No. 03-13: Applying the Conditions in Paragraph 42 of FASB
Statement No. 144 in Determining Whether to Report Discontinued Operations. The
Issue provides a model to assist in evaluating (a) which cash flows should be
considered in the determination of whether cash flows of the disposal component
have been or will be eliminated from the ongoing operations of the entity and
(b) the types of continuing involvement that constitute significant continuing
involvement in the operations of the disposal component. FASB is expected to
ratify the consensus at its November 2004 meeting with prospective application
to transactions entered into after January 1, 2005. The Company considered the
model outlined in EITF Issue No. 03-13 while evaluating the sales of the
Canadian and Rockies disposal groups (see Note 8 for more information) and does
not expect the new guidance to change the conclusions reached under the existing
discontinued operations guidance in SFAS No. 144.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in Item 2.
Item 4. Controls and Procedures.
The Company's senior management, including the Company's Chief Executive
Officer and Chief Financial Officer, evaluated the effectiveness of the
Company's disclosure controls and procedures as of the end of the period covered
by this quarterly report. Based upon this evaluation, the Company's Chairman,
President and Chief Executive Officer along with the Company's Executive Vice
President and Chief Financial Officer concluded that the Company's disclosure
controls and procedures are effective in ensuring that information we are
required to disclose in reports that we file or submit under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the
time periods specified in Securities and Exchange Commission rules and forms.
There was no change in our internal control over financial reporting that
occurred during the period covered by this Quarterly Report on Form 10-Q that
has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting. The certificates required by this
item are filed as Exhibit 31 to this Form 10-Q. See "Risk Factor" in the
Management's Discussion and Analysis of Financial Condition and Results of
Operations for a discussion of risks related to Section 404 of the
Sarbanes-Oxley Act of 2002.
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings.
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, 14 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 11 actions are virtually identical--they are filed by three
law firms, in conjunction with other law firms as co-counsel. All 11 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 "Ser action"). 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, as amended (the "Securities Act"), 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 15 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 Securities 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 Section 15 of the Securities
Act 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 23, 2004.
In a separate order dated February 4, 2004, the court denied without
prejudice Mr. 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.
In July 2004 the court issued an order for pretrial preparation
establishing a trial date on November 7, 2005. On August 31, 2004, Calpine filed
a motion for summary judgment to dismiss the consolidated securities class
action lawsuits described above in Note 12. On November 3, 2004, the court
issued an order denying such motion for summary judgment. Discovery is underway
and a trial is scheduled for November 7, 2005. 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. 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. Limited document production has taken
place. Negotiations have been taking place between counsel and further
production of documents will occur once the court enters a protective order
governing the use of confidential information in this action. 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
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 filed its response,
in the form of a motion to dismiss, on or about 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
million, which was approved by the Bankruptcy Court on June 16, 2004. On October
15, 2004, the preference lawsuit was dismissed with prejudice, given that
Calpine had made the final settlement payment prior to that date. Additionally,
the Trustee returned the original Stipulated Judgment to Calpine. Therefore,
this matter has been fully concluded.
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 arising out of an amended Energy Services Agreement ("ESA") by
failing to disclose facts surrounding the termination, effective May 8, 1998, of
one of AELLC's fixed-cost gas supply agreements. The steam price paid by IP
under the ESA is derived from AELLC's cost of gas under its 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).
The case recently proceeded to trial, and on November 3, 2004, a jury
verdict in the amount of $41 million was rendered in favor of IP. AELLC was held
liable on the misrepresentation claim, but not on the breach of contract claim.
The verdict amount was based on calculations proffered by IP's damages expert,
and AELLC is currently reviewing post-trial motions and appellate options. AELLC
made an additional accrual to recognize the jury verdict and the Company
recognized its 32.3% share."
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 through
December 1, 2003) 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. On August 17, 2004, the case was transferred
to a different judge, which will likely delay the ruling on the motion to
dismiss. 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 20 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 eight other
similar complaints for violations of Section 17200. All eight 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
Section 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. FERC dismissed the complaint in an order issued on
June 26, 2003, and subsequently denied rehearing of that order. The matter is
pending on appeal before the United States Court of Appeals for the Ninth
Circuit.
Transmission Service Agreement with Nevada Power Company. 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 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 certain costs incurred by NPC in
connection with the second phase of the project (approximately $4.5 million in
total to date) 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.
The bond issued by FFIC, by its terms, expired on May 1, 2004. On or about
April 27, 2004, NPC asserted to FFIC that Calpine had committed a default under
the bond by failing to agree to renew or replace the bond upon its expiration
and made demand on FFIC for the full amount of the surety bond, $33,333,333. On
April 29, 2004, FFIC filed a complaint for declaratory relief in state superior
court of Marin County, California in connection with this demand. If FFIC is
successful in its petition, it will be entitled to recover its costs associated
with bringing this action.
FFIC's superior court complaint asks that an order be issued declaring that
it has no obligation to make payment under the bond. Further, if the court were
to determine that FFIC does have an obligation to make payment, FFIC asked 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 filed an answer
denying the allegations of the complaint and asserting affirmative defenses,
including that it has fully performed its obligations under the TSA and surety
bond. NPC filed a motion to quash service for lack of personal jurisdiction in
California.
On September 3, 2004, the superior court granted NPC's motion, and NPC was
dismissed from the proceeding. Subsequently, FFIC agreed to dismiss the
complaint as to Calpine. On September 30, 2004 NPC filed a complaint in state
district court of Clark County, Nevada against Calpine, Moapa Energy Center,
LLC, FFIC and unnamed parties alleging, among other things, breach by Calpine of
its obligations under the TSA and breach by FFIC of its obligations under the
surety bond. At this time, Calpine is unable to predict the outcome of this
proceeding.
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 US$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
US$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 of
National Energy Systems Company ("NESCO"). 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
occurred in September 2004 and the daily reduction in the payment amount has
reduced the $18.0 million payment to zero. Calpine has made the $6 million
payment to the estates. 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 filed a motion to
recover attorneys' fees from NESCO, which was recently granted at a reduced
amount. Calpine held back $100,000 of the $6 million payment to ensure payment
of these fees.
Calpine Energy Services v Acadia Power Partners. Calpine, through its
subsidiaries, owns 50% of Acadia Power Partners, LLC ("APP") which company owns
the Acadia Energy Center near Eunice, Louisiana (the "Facility"). A Cleco Corp
subsidiary owns the remaining 50% of APP. Calpine Energy Services, LP ("CES") is
the purchaser under two power purchase agreements with APP, which agreements
entitle CES to all of the Facility's capacity and energy. In August 2003 certain
transmission constraints previously unknown to CES and APP began to severely
limit the ability of CES to obtain all of the energy from the Facility. CES has
asserted that it is entitled to certain relief under the purchase agreements, to
which assertions APP disagrees. Accordingly, the parties are engaging in the
initial alternative dispute resolution steps set forth in the power purchase
agreements. It is possible that the dispute will result in binding arbitration
pursuant to the agreements if a settlement is not reached. In addition, CES and
APP are discussing certain billing calculation disputes, which relate to
operating efficiency. The period of time for these disputes is also at issue,
and could range from six months to June 2002 (commercial operation date of
plant). It is expected that the parties will be able to resolve these disputes,
and that APP will owe CES approximately $800,000 to $2.5 million.
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.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
On July 1, 2004, the Company issued 4.2 million unregistered shares of its
common stock in exchange for $20.0 million par value of HIGH TIDES I, which are
exchangeable for common stock. 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. On September 30, 2004, the Company repurchased par value of
$115.0 million HIGH TIDES III, which are exchangeable for common stock.
The following table sets forth the total units of HIGH TIDES purchased by
the Company during the third quarter:
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
- ----------------- ---------------- ------------------ ----------------- ----------------
7/1/04-7/31/04 400,000 $ 50.68 -- --
8/1/04-8/31/04 -- -- -- --
9/1/04-9/30/04 2,300,000 $ 48.50 -- --
On September 30, 2004, the Company also repurchased $266.2 million in
principal amount of its 4.75% Contingent Convertible Senior Notes Due 2023
("2023 Convertible Senior Notes"), which are convertible into common stock. The
following table sets forth the total units of 2023 Convertible Senior Notes
purchased by the Company during the third quarter:
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 Note or Programs or Programs
- ----------------- ---------------- ------------------ ----------------- ----------------
7/1/04-7/31/04 -- -- -- --
8/1/04-8/31/04 -- -- -- --
9/1/04-9/30/04 266,225 $ 665.02 -- --
Item 6. 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.(a)
*3.2 Amended and Restated By-laws of Calpine Corporation.(b)
*4.1 Indenture, dated as of September 30, 2004, between Calpine Corporation
and Wilmington Trust Company, as Trustee, relating to $785,000,000 in
aggregate principal amount of 9.625% First Priority Senior Secured
Notes due 2014, including form of Notes.(c)
*4.2.1 Indenture, dated as of August 10, 2000, between the Company and
Wilmington Trust Company, as Trustee.(d)
*4.2.2 First Supplemental Indenture, dated as of September 28, 2000, between
the Company and Wilmington Trust Company, as Trustee.(e)
*4.2.3 Second Supplemental Indenture, dated as of September 30, 2004, between
the Company and Wilmington Trust Company, as Trustee, relating to
$736,000,000 in aggregate principal amount at maturity of Contingent
Convertible Notes due 2014, including form of Notes.(f)
*4.3.1 Amended and Restated Rights Agreement, dated as of September 19, 2001,
between Calpine Corporation and Equiserve Trust Company, N.A., as
Rights Agent.(g)
*4.3.2 Amendment No. 1 to Rights Agreement, dated as of September 28, 2004,
between Calpine Corporation and EquiServe Trust Company, N.A., as
Rights Agent.(f)
4.4 Memorandum and Articles of Association of Calpine (Jersey) Limited.
(h)
*10.1 Share Lending Agreement, dated as of September 28, 2004, among Calpine
Corporation, as Lender, Deutsche Bank AG London, as Borrower, through
Deutsche Bank Securities Inc., as agent for the Borrower, and Deutsche
Bank Securities Inc., in its capacity as Collateral Agent and
Securities Intermediary.(f)
*10.2 Purchase and Sale Agreement among Calpine Corporation, Calpine Natural
Gas L.P. and Pogo Producing Company dated July 1, 2004.(i)
*10.3 Purchase and Sale Agreement among Calpine Corporation, Calpine Natural
Gas L.P. and Bill Barrett Corporation dated July 1, 2004.(i)
*10.4 Asset and Trust Unit Purchase and Sale Agreement among Calpine Canada
Natural Gas Partnership and Calpine Energy Holdings Limited and
Calpine Corporation and PrimeWest Gas Corp. and PrimeWest Energy Trust
dated July 1, 2004.(i)
*10.5.1 Letter of Credit Agreement, dated as of July 16, 2003, among Calpine
Corporation, the Lenders named therein, and The Bank of Nova Scotia,
as Administrative Agent.(j)
+10.5.2 Amendment to Letter of Credit Agreement, dated as of September 30,
2004, between Calpine Corporation and The Bank of Nova Scotia, as
Administrative Agent.
+10.6 Letter of Credit Agreement, dated as of September 30, 2004, between
Calpine Corporation and Bayerische Landesbank, acting through its
Cayman Islands Branch, as the Issuer.
+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 302of
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 Section906
of the Sarbanes-Oxley Act of 2002.
+99.1 Term Debenture, issued August 23, 2001, by Calpine Canada Resources
Ltd., to Calpine Canada Energy Finance II ULC.
- ----------
+ Filed herewith.
* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated June 30, 2004, filed with the SEC on August 9, 2004.
(b) 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.
(c) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on October 6, 2004.
(d) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17,
2002.
(e) 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.
(f) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on September 30, 2004.
(g) Incorporated by reference to Calpine Corporation's Registration Statement
on Form 8-A/A (Registration No. 001-12079) filed with the SEC on September
28, 2001.
(h) This document has been omitted in reliance on Item 601(b)(4)(iii) of
Regulation S-K. The Company agrees to furnish a copy of such document to
the SEC upon request.
(i) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K/A filed with the SEC on September 14, 2004.
(j) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.
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: November 9, 2004
By:/s/ CHARLES B. CLARK, JR.
--------------------------
Charles B. Clark, Jr.
Senior Vice President and Corporate
Controller (Principal Accounting Officer)
Date: November 9, 2004
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.(a)
*3.2 Amended and Restated By-laws of Calpine Corporation.(b)
*4.1 Indenture, dated as of September 30, 2004, between Calpine Corporation
and Wilmington Trust Company, as Trustee, relating to $785,000,000 in
aggregate principal amount of 9.625% First Priority Senior Secured
Notes due 2014, including form of Notes.(c)
*4.2.1 Indenture, dated as of August 10, 2000, between the Company and
Wilmington Trust Company, as Trustee.(d)
*4.2.2 First Supplemental Indenture, dated as of September 28, 2000, between
the Company and Wilmington Trust Company, as Trustee.(e)
*4.2.3 Second Supplemental Indenture, dated as of September 30, 2004, between
the Company and Wilmington Trust Company, as Trustee, relating to
$736,000,000 in aggregate principal amount at maturity of Contingent
Convertible Notes due 2014, including form of Notes.(f)
*4.3.1 Amended and Restated Rights Agreement, dated as of September 19, 2001,
between Calpine Corporation and Equiserve Trust Company, N.A., as
Rights Agent.(g)
*4.3.2 Amendment No. 1 to Rights Agreement, dated as of September 28, 2004,
between Calpine Corporation and EquiServe Trust Company, N.A., as
Rights Agent.(f)
4.4 Memorandum and Articles of Association of Calpine (Jersey) Limited.
(h)
*10.1 Share Lending Agreement, dated as of September 28, 2004, among Calpine
Corporation, as Lender, Deutsche Bank AG London, as Borrower, through
Deutsche Bank Securities Inc., as agent for the Borrower, and Deutsche
Bank Securities Inc., in its capacity as Collateral Agent and
Securities Intermediary.(f)
*10.2 Purchase and Sale Agreement among Calpine Corporation, Calpine Natural
Gas L.P. and Pogo Producing Company dated July 1, 2004.(i)
*10.3 Purchase and Sale Agreement among Calpine Corporation, Calpine Natural
Gas L.P. and Bill Barrett Corporation dated July 1, 2004.(i)
*10.4 Asset and Trust Unit Purchase and Sale Agreement among Calpine Canada
Natural Gas Partnership and Calpine Energy Holdings Limited and
Calpine Corporation and PrimeWest Gas Corp. and PrimeWest Energy Trust
dated July 1, 2004.(i)
*10.5.1 Letter of Credit Agreement, dated as of July 16, 2003, among Calpine
Corporation, the Lenders named therein, and The Bank of Nova Scotia,
as Administrative Agent.(j)
+10.5.2 Amendment to Letter of Credit Agreement, dated as of September 30,
2004, between Calpine Corporation and The Bank of Nova Scotia, as
Administrative Agent.
+10.6 Letter of Credit Agreement, dated as of September 30, 2004, between
Calpine Corporation and Bayerische Landesbank, acting through its
Cayman Islands Branch, as the Issuer.
+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 302of
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 Section906
of the Sarbanes-Oxley Act of 2002.
+99.1 Term Debenture, issued August 23, 2001, by Calpine Canada Resources
Ltd., to Calpine Canada Energy Finance II ULC.
- ----------
+ Filed herewith.
* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated June 30, 2004, filed with the SEC on August 9, 2004.
(b) 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.
(c) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on October 6, 2004.
(d) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17,
2002.
(e) 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.
(f) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on September 30, 2004.
(g) Incorporated by reference to Calpine Corporation's Registration Statement
on Form 8-A/A (Registration No. 001-12079) filed with the SEC on September
28, 2001.
(h) This document has been omitted in reliance on Item 601(b)(4)(iii) of
Regulation S-K. The Company agrees to furnish a copy of such document to
the SEC upon request.
(i) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K/A filed with the SEC on September 14, 2004.
(j) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.