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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, 2005
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
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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:
569,382,412 shares of Common Stock, par value $.001 per share, outstanding
on November 8, 2005.
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CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2005
INDEX
Page No.
--------
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Condensed Balance Sheets September 30, 2005 and December 31, 2004.......... 5
Consolidated Condensed Statements of Operations for the Three and Nine Months Ended
September 30, 2005 and 2004........................................................... 7
Consolidated Condensed Statements of Cash Flows for the Nine Months Ended
September 30, 2005 and 2004........................................................... 9
Notes to Consolidated Condensed Financial Statements...................................... 11
1. Organization and Operations of the Company..................................... 11
2. Summary of Significant Accounting Policies..................................... 11
3. Strategic Initiative........................................................... 16
4. Available-for-Sale Debt Securities............................................. 19
5. Property, Plant and Equipment, Net and Capitalized Interest.................... 20
6. Unconsolidated Investments..................................................... 22
7. Debt........................................................................... 25
8. Discontinued Operations........................................................ 29
9. Derivative Instruments......................................................... 34
10. Comprehensive Income (Loss).................................................... 38
11. Loss Per Share................................................................. 40
12. Commitments and Contingencies.................................................. 42
13. Operating Segments............................................................. 49
14. California Power Market........................................................ 50
15. Subsequent Events.............................................................. 52
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..... 52
Selected Operating Information.......................................................... 53
Overview................................................................................ 54
Results of Operations................................................................... 57
Liquidity and Capital Resources......................................................... 72
Performance Metrics..................................................................... 81
Summary of Key Activities............................................................... 84
California Power Market................................................................. 85
Financial Market Risks.................................................................. 85
New Accounting Pronouncements........................................................... 93
Item 3. Quantitative and Qualitative Disclosures About Market Risk................................ 93
Item 4. Controls and Procedures................................................................... 94
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings......................................................................... 95
Item 6. Exhibits.................................................................................. 95
Signatures.................................................................................................... 99
- 2 -
DEFINITIONS
As used in this Form 10-Q, the abbreviations contained herein have the
meanings set forth below. Additionally, the terms, "Calpine," "we," "us" and
"our" refer to Calpine Corporation and its subsidiaries, unless the context
clearly indicates otherwise.
ABBREVIATION DEFINITION
- ------------ ----------
2004 Form 10-K Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2004,
filed with the SEC on March 31, 2005
2006 Convertible Notes 4% Convertible Senior Notes Due 2006
2014 Convertible Notes 6% Contingent Convertible Notes Due 2014
2015 Convertible Notes 7 3/4% Contingent Convertible Notes Due 2015
2023 Convertible Notes 4 3/4% Contingent Convertible Senior Notes Due 2023
Acadia PP Acadia Power Partners, LLC
AELLC Androscoggin Energy LLC
Agnews O.L.S. Energy - Agnews, Inc.
AICPA American Institute of Certified Public Accountants
AOCI Accumulated Other Comprehensive Income
APB Accounting Principles Board
ARB Accounting Research Bulletin
Auburndale PP Auburndale Power Partners, Limited Partnership
Bcfe Billion cubic feet equivalent
Bear Stearns Bear Stearns Companies, Inc.
Btu British thermal units
CAISO California Independent System Operator
CalBear CalBear Energy, LP
CalGen Calpine Generating Company, LLC, formerly Calpine Construction Finance Company II, LLC
Calpine Canada Calpine Canada Natural Gas Partnership
Calpine Cogen Calpine Cogeneration Corporation, formerly Cogen America
Calpine Jersey I Calpine (Jersey) Limited
Calpine Jersey II Calpine European Funding (Jersey) Limited
CalPX California Power Exchange
CCFC I Calpine Construction Finance Company, L.P
CCFC LLC CCFC Preferred Holdings, LLC
CCRC Calpine Canada Resources Company, f/k/a/ Calpine Canada Resources Ltd.
CDWR California Department of Water Resources
CES Calpine Energy Services, L.P.
CFE Comision Federal de Electricidad
Chubu Chubu Electric Power Company, Inc.
CIP Construction in Progress
CMSC Calpine Merchant Services Company, Inc.
CNEM Calpine Northbrook Energy Marketing, LLC
CNGT Calpine Natural Gas Trust
Cogen America Cogeneration Corporation of America, now called Calpine Cogeneration Corporation
COR Cost of revenue
CPIF Calpine Power Income Fund
CPLP Calpine Power, L.P.
CPUC California Public Utilities Commission
CTA Cumulative Translation Adjustment
DB London Deutsche Bank AG London
Deer Park Deer Park Energy Center Limited Partnership
Diamond Diamond Generating Corporation
DOL United States Department of Labor
E&S Electricity and steam
EITF Emerging Issues Task Force
Enron Enron Corp
Enron Canada Enron Canada Corp.
Entergy Entergy Services, Inc.
EOB Electricity Oversight Board
EPS Earnings per share
ERISA Employee Retirement Income Security Act
ESA Energy Services Agreement
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FFIC Fireman's Fund Insurance Company
FIN FASB Interpretation Number
First Priority Notes 9 5/8% First Priority Senior Secured Notes Due 2014
GAAP Generally accepted accounting principles
GE General Electric International, Inc.
Geysers Geysers Power Company, LLC
Grays Ferry Grays Ferry Cogeneration Partnership
Hawaii Fund Hawaii Structural Ironworkers Pension Trust Fund
HBO Hedging, balancing and optimization
Heat rate A measure of the amount of fuel required to produce a unit of electricity
HIGH TIDES Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities
(HIGH TIDES SM)
IP International Paper Company
KW Kilowatt(s)
KWh Kilowatt hour(s)
LCRA Lower Colorado River Authority
- 3 -
ABBREVIATION DEFINITION
- ------------ ----------
LIBOR London Inter-Bank Offered Rate
LNG Liquid natural gas
LTSA Long Term Service Agreement
Metcalf Metcalf Energy Center, LLC
Mitsui Mitsui & Co., Ltd.
MLCI Merrill Lynch Commodities, Inc.
MMBtu Million Btu
Mmcfe Million net cubic feet equivalent
Morris Morris Cogeneration, LLC, formerly known as Calpine Morris, LLC
MW Megawatt(s)
MWh Megawatt hour(s)
NESCO National Energy Systems Company
NOL Net operating loss
NPC Nevada Power Company
O&M Operations and maintenance
OCI Other Comprehensive Income
Oneta Oneta Energy Center
Ontelaunee Ontelaunee Energy Center
OPA Ontario Power Authority
Panda Panda Energy International, Inc., and related party PLC II, LLC
PCF Power Contract Financing, L.L.C.
PCF III Power Contract Financing III, LLC
PJM Pennsylvania-New Jersey-Maryland
Plan Calpine Corporation Retirement Savings Plan
POX Plant operating expense
PPA(s) Power purchase agreement(s)
PSM Power Systems MFG., LLC
PUCN Public Utilities Commission of Nevada
QF Qualifying Facilities
Reliant Reliant Energy Services, Inc.
RMR Contracts Reliability must run contracts
Rosetta Rosetta Resources Inc.
SAB Staff Accounting Bulletin
Saltend Saltend Energy Centre
SEC Securities and Exchange Commission
Second Priority Notes Calpine Corporation's Second Priority Senior Secured Floating Rate Notes due 2007,
8.500% Second Priority Senior Secured Notes due 2010, 8.750% Second Priority Senior
Secured Notes due 2013 and 9.875% Second Priority Senior Secured Notes due 2011
Second Priority Secured Debt The Indentures between the Company and Wilmington Trust Company, as Trustee, relating to the
Instruments Company's Second Priority Senior Secured Floating Rate Notes due 2007, 8.500% Second
Priority Senior Secured Notes due 2010, 8.750% Second Priority Senior Secured Notes due
2013, 9.875% Second Priority Senior Secured Notes due 2011 and the Credit Agreement among
the Company, as Borrower, Goldman Sachs Credit Partners L.P., as Administrative Agent,
Sole Lead Arranger and Sole Book Runner, The Bank of Nova Scotia, as Arranger and
Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-
Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of
California, N.A., as Managing Agent, relating to the Company's Senior Secured Term Loans
Due 2007, in each case as such instruments may be amended from time to time.
Securities Act Securities Act of 1933, as amended
Senior Secured Noteholders Holders of the First Priority Notes and the Second Priority Notes
SFAS Statement of Financial Accounting Standards
Siemens-Westinghouse Siemens-Westinghouse Power Corporation (changed to "Siemens Power Generation, Inc. on
August 1, 2005)
SkyGen SkyGen Energy LLC, now called Calpine Northbrook Energy, LLC
SPE Special-Purpose Entities
SPPC Sierra Pacific Power Company
TAC Third Amended Complaint
TNAI Thermal North America, Inc.
TSA(s) Transmission service agreement(s)
TTS Thomassen Turbine Systems, B.V.
Valladolid Compania de Generacion Valladolid S.de R.L. de C.V. partnership
VIE(s) Variable interest entity(ies)
Westcoast Westcoast Energy Inc.
Whitby Whitby Cogeneration Limited Partnership
Williams The Williams Companies, Inc.
- 4 -
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
September 30, 2005 and December 31, 2004
September 30, December 31,
2005 2004
-------------- ---------------
(In thousands, except share and
per share amounts)
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents......................................................................... $ 843,136 $ 718,023
Accounts receivable, net.......................................................................... 1,537,620 1,043,061
Margin deposits and other prepaid expense......................................................... 415,331 437,593
Inventories....................................................................................... 151,672 171,639
Restricted cash................................................................................... 1,106,685 593,304
Current derivative assets......................................................................... 703,665 324,206
Current assets held for sale...................................................................... 47,152 142,096
Other current assets.............................................................................. 232,741 133,643
-------------- --------------
Total current assets.......................................................................... 5,038,002 3,563,565
-------------- --------------
Restricted cash, net of current portion........................................................... 204,433 157,868
Notes receivable, net of current portion.......................................................... 194,076 203,680
Project development costs......................................................................... 135,291 150,179
Unconsolidated investments........................................................................ 348,058 373,108
Deferred financing costs.......................................................................... 363,513 406,844
Prepaid lease, net of current portion............................................................. 467,658 424,586
Property, plant and equipment, net................................................................ 18,542,923 18,397,743
Goodwill.......................................................................................... 45,160 45,160
Other intangible assets, net...................................................................... 66,410 68,423
Long-term derivative assets....................................................................... 925,251 506,050
Long-term assets held for sale.................................................................... 210,213 2,260,401
Other assets...................................................................................... 547,249 658,481
-------------- --------------
Total assets................................................................................. $ 27,088,237 $ 27,216,088
============== ==============
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable................................................................................ $ 1,192,408 $ 980,280
Accrued payroll and related expense............................................................. 85,205 87,659
Accrued interest payable........................................................................ 406,752 385,794
Income taxes payable............................................................................ 64,562 57,234
Notes payable and borrowings under lines of credit, current portion............................. 208,145 200,076
Preferred interests, current portion............................................................ 159,453 8,641
Capital lease obligation, current portion....................................................... 7,143 5,490
CCFC I financing, current portion............................................................... 3,208 3,208
Construction/project financing, current portion................................................. 85,891 93,393
Senior notes and term loans, current portion.................................................... 967,892 718,449
Current derivative liabilities.................................................................. 974,097 356,030
Current liabilities held for sale............................................................... 6,623 86,458
Other current liabilities....................................................................... 355,790 302,680
-------------- --------------
Total current liabilities..................................................................... 4,517,169 3,285,392
-------------- --------------
Notes payable and borrowings under lines of credit, net of current portion........................ 586,770 769,490
Convertible debentures payable to Calpine Capital Trust III....................................... -- 517,500
Preferred interests, net of current portion....................................................... 283,615 497,896
Capital lease obligation, net of current portion.................................................. 281,045 283,429
CCFC I financing, net of current portion.......................................................... 780,901 783,542
CalGen/CCFC II financing.......................................................................... 2,396,720 2,395,332
Construction/project financing, net of current portion............................................ 2,361,716 1,905,658
Convertible Notes................................................................................. 1,833,790 1,255,298
Senior notes and term loans, net of current portion............................................... 7,231,719 8,532,664
Deferred income taxes, net of current portion..................................................... 1,109,073 885,754
Deferred revenue.................................................................................. 139,834 114,202
Long-term derivative liabilities.................................................................. 1,215,463 516,230
Long-term liabilities held for sale............................................................... -- 176,299
Other liabilities................................................................................. 217,257 316,284
-------------- --------------
Total liabilities............................................................................. 22,955,072 22,234,970
-------------- --------------
Minority interests................................................................................ 403,197 393,445
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(table continues)
- 5 -
September 30, December 31,
2005 2004
-------------- ---------------
(In thousands, except share and
per share amounts)
(Unaudited)
LIABILITIES & STOCKHOLDERS' EQUITY
Commitments and Contingencies (Note 12)
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and
outstanding in 2005 and 2004................................................................... -- --
Common stock, $.001 par value per share; authorized 2,000,000,000 shares; issued and
outstanding 569,382,412 shares in 2005 and 536,509,231 shares in 2004.......................... 569 537
Additional paid-in capital...................................................................... 3,262,604 3,151,577
Additional paid-in capital, loaned shares....................................................... 258,100 258,100
Additional paid-in capital, returnable shares................................................... (258,100) (258,100)
Retained earnings............................................................................... 642,169 1,326,048
Accumulated other comprehensive income (loss)................................................... (175,374) 109,511
-------------- --------------
Total stockholders' equity................................................................. 3,729,968 4,587,673
-------------- --------------
Total liabilities and stockholders' equity................................................. $ 27,088,237 $ 27,216,088
============== ==============
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
- 6 -
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three and Nine Months Ended September 30, 2005 and 2004
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- ---------------------------
2005 2004 2005 2004
----------- ----------- ----------- ------------
(In thousands, except per share amounts)
(Unaudited)
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue ...................................... $ 2,096,323 $ 1,544,329 $ 4,625,078 $ 3,851,914
Transmission sales revenue ......................................... 1,902 4,427 8,791 14,152
Sales of purchased power for hedging and optimization .............. 413,281 427,737 1,193,537 1,301,585
----------- ----------- ----------- -----------
Total electric generation and marketing revenue ................... 2,511,506 1,976,493 5,827,406 5,167,651
Oil and gas production and marketing revenue
Oil and gas sales .................................................. -- 2,690 -- 4,707
Sales of purchased gas for hedging and optimization ................ 696,850 423,733 1,574,067 1,258,441
----------- ----------- ----------- -----------
Total oil and gas production and marketing revenue ................ 696,850 426,423 1,574,067 1,263,148
Mark-to-market activities, net ....................................... 40,854 (5,229) 40,197 (15,316)
Other revenue ........................................................ 32,380 14,046 84,558 50,849
----------- ----------- ----------- -----------
Total revenue ................................................... 3,281,590 2,411,733 7,526,228 6,466,332
----------- ----------- ----------- -----------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense ............................................ 180,336 159,957 555,433 522,237
Transmission purchase expense ...................................... 23,088 22,706 63,770 53,783
Royalty expense .................................................... 9,988 8,343 28,348 21,067
Purchased power expense for hedging and optimization ............... 343,778 348,380 960,110 1,165,674
----------- ----------- ----------- -----------
Total electric generation and marketing expense ................... 557,190 539,386 1,607,661 1,762,761
Oil and gas operating and marketing expense
Oil and gas operating expense ...................................... 1,393 1,837 4,318 5,824
Purchased gas expense for hedging and optimization ................. 724,351 429,373 1,623,692 1,243,781
----------- ----------- ----------- -----------
Total oil and gas operating and marketing expense ................. 725,744 431,210 1,628,010 1,249,605
Fuel expense ......................................................... 1,567,504 1,052,309 3,336,248 2,671,860
Depreciation, depletion and amortization expense ..................... 131,006 117,391 371,340 324,871
Operating lease expense .............................................. 28,792 25,805 79,097 80,567
Other cost of revenue ................................................ 32,227 19,187 102,547 68,177
----------- ----------- ----------- -----------
Total cost of revenue ........................................... 3,042,463 2,185,288 7,124,903 6,157,841
----------- ----------- ----------- -----------
Gross profit ................................................... 239,127 226,445 401,325 308,491
(Income) loss from unconsolidated investments .......................... (5,384) 11,202 (14,644) 12,174
Equipment cancellation and impairment cost ............................. 761 7,820 689 10,187
Long-term service agreement cancellation charge ........................ 553 3,981 34,445 3,981
Project development expense ............................................ 10,098 3,366 71,639 15,114
Research and development expense ....................................... 3,342 3,982 15,502 12,921
Sales, general and administrative expense .............................. 54,593 53,770 176,318 156,008
----------- ----------- ----------- -----------
Income from operations ............................................... 175,164 142,324 117,376 98,106
Interest expense ....................................................... 380,994 285,446 1,027,382 791,242
Interest (income) ...................................................... (26,640) (16,957) (57,417) (37,996)
Minority interest expense .............................................. 10,977 9,990 31,763 23,149
(Income) from repurchase of debt ....................................... (15,530) (167,154) (166,456) (170,548)
Other expense (income), net ............................................ 50,311 22,446 71,446 (168,934)
----------- ----------- ----------- -----------
Income (loss) before benefit for income taxes ........................ (224,948) 8,553 (789,342) (338,807)
Provision (benefit) for income taxes ................................... 17,487 (20,324) (167,866) (144,332)
----------- ----------- ----------- -----------
Income (loss) before discontinued operations ......................... (242,435) 28,877 (621,476) (194,475)
Discontinued operations, net of tax provision of $170,514, $102,282,
$137,629 and $92,061 ................................................. 25,746 112,248 (62,403) 235,710
----------- ----------- ----------- -----------
Net income (loss) .............................................. $ (216,689) $ 141,125 $ (683,879) $ 41,235
=========== =========== =========== ===========
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding................... 478,461 444,380 458,483 425,682
Income (loss) before discontinued operations.......................... $ (0.51) $ 0.07 $ (1.36) $ (0.45)
Discontinued operations, net of tax................................... $ 0.06 $ 0.25 $ (0.13) $ 0.55
----------- ----------- ----------- -----------
Net income (loss)............................................... $ (0.45) $ 0.32 $ (1.49) $ 0.10
=========== =========== =========== ===========
(table continues)
- 7 -
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- ---------------------------
2005 2004 2005 2004
----------- ----------- ----------- ------------
(In thousands, except per share amounts)
(Unaudited)
Diluted earnings per common share:
Weighted average shares of common stock outstanding................... 478,461 446,922 458,483 425,682
Income (loss) before discontinued operations.......................... $ (0.51) $ 0.07 $ (1.36) $ (0.45)
Discontinued operations, net of tax................................... $ 0.06 $ 0.25 $ (0.13) $ 0.55
----------- ----------- ----------- -----------
Net income (loss)............................................... $ (0.45) $ 0.32 $ (1.49) $ 0.10
=========== =========== =========== ===========
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
- 8 -
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2005 and 2004
Nine Months Ended
September 30,
-----------------------------
2005 2004
------------ ------------
(In thousands)
(Unaudited)
Cash flows from operating activities:
Net income (loss) .............................................................................. $ (683,879) $ 41,235
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion and amortization (1) ................................................... 596,118 598,856
Impairment charges on power projects............................................................ 261,532 --
Development cost write-off ..................................................................... 46,958 --
Deferred income taxes, net ..................................................................... (30,237) (52,272)
Gain on sale of assets ......................................................................... (351,950) (348,053)
Stock compensation expense ..................................................................... 16,430 15,190
Foreign exchange losses ........................................................................ 57,182 7,521
(Income) from repurchase of debt ............................................................... (166,456) (170,548)
Change in net derivative assets and liabilities ................................................ 17,041 40,782
(Income) loss from unconsolidated investments .................................................. (14,804) 11,663
Distributions from unconsolidated investments .................................................. 16,862 22,263
Other .......................................................................................... 32,452 74,573
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable .......................................................................... (416,488) (104,787)
Other current assets ......................................................................... 15,788 (1,202)
Other assets ................................................................................. (35,587) (66,224)
Accounts payable and accrued expense ......................................................... 205,737 218,862
Other liabilities ............................................................................ 25,328 (57,989)
----------- -----------
Net cash provided by (used in) operating activities ........................................ (407,973) 229,870
----------- -----------
Cash flows from investing activities:
Purchases of property, plant and equipment ..................................................... (675,714) (1,184,352)
Disposals of property, plant and equipment ..................................................... 1,860,981 1,065,834
Disposal of subsidiary ......................................................................... -- 85,412
Disposal of investment ......................................................................... 36,900 --
Acquisitions, net of cash acquired ............................................................. -- (187,786)
Advances to unconsolidated investments ......................................................... -- (8,833)
Project development costs ...................................................................... (13,095) (23,605)
Investment in HIGH TIDES ....................................................................... -- (111,550)
Disposal of HIGH TIDES investment .............................................................. 132,500 --
Sale of collateral securities .................................................................. -- 93,963
Increase in restricted cash .................................................................... (559,946) (124,153)
Decrease in notes receivable ................................................................... 759 9,979
Other .......................................................................................... 40,304 3,157
----------- -----------
Net cash provided by (used in) investing activities ........................................ 822,689 (381,934)
----------- -----------
Cash flows from financing activities:
Borrowings from notes payable and lines of credit .............................................. 6,488 97,191
Repayments of notes payable and lines of credit ................................................ (808,784) (328,943)
Borrowings from project financing .............................................................. 620,956 3,477,854
Repayments of project financing ................................................................ (176,799) (2,942,272)
Repayments and repurchases of senior notes ..................................................... (821,252) (630,275)
Repurchase of convertible senior notes ......................................................... (15) (586,926)
Proceeds from issuance of convertible senior notes ............................................. 650,000 867,504
Proceeds from issuance of senior debt offerings ................................................ -- 878,815
Proceeds from preferred interests (2) .......................................................... 565,000 --
Repayment of convertible debentures to Calpine Capital Trust III ............................... (517,500) --
Proceeds from prepaid commodity contract (3) ................................................... 290,571 --
Financing and transaction costs ................................................................ (89,318) (175,802)
Other .......................................................................................... (28,318) (23,443)
----------- -----------
Net cash provided by (used in) financing activities ........................................ (308,971) 633,703
----------- -----------
Effect of exchange rate changes on cash and cash equivalents ..................................... 741 14,377
Net decrease in cash and cash equivalents including discontinued operations cash ................. 106,486 496,016
Change in discontinued operations cash classified as current assets held for sale ................ 18,627 7,694
----------- -----------
Net increase in cash and cash equivalents ...................................................... 125,113 503,710
----------- -----------
Cash and cash equivalents, beginning of period ................................................... 718,023 954,827
Cash and cash equivalents, end of period ......................................................... $ 843,136 $ 1,458,537
=========== ===========
Cash paid during the period for:
Interest, net of amounts capitalized ........................................................... $ 962,866 $ 674,875
Income taxes ................................................................................... $ 23,653 $ 21,863
- ------------
(table continues)
- 9 -
<FN>
(1) Includes depreciation and amortization that is also charged to sales,
general and administrative expense and to interest expense in the
Consolidated Condensed Statements of Operations.
(2) Relates to the $260.0 million Calpine Jersey II, $155.0 million Metcalf and
$150.0 million CCFC LLC offerings of redeemable preferred securities. See
Note 7 of the accompanying notes.
(3) Relates to the Deer Park prepaid commodity contract. See Note 9 of the
accompanying notes.
Schedule of non-cash investing and financing activities:
2005 Issuance of 27.5 million shares of common stock in exchange for $94.3
million in principal amount at maturity of 2014 Convertible Notes
2004 Acquired the remaining 50% interest in the Aries power plant for $3.7
million cash and $220.0 million of assumed liabilities, including debt
of $173.2 million.
2004 Issuance of 24.3 million shares of common stock in exchange for $40.0
million par value of HIGH TIDES I preferred securities and $75.0
million par value of HIGH TIDES II preferred securities.
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 11 of the accompanying notes 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.
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
</FN>
- 10 -
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
September 30, 2005
(Unaudited)
1. Organization and Operations of the Company
Calpine Corporation, a Delaware corporation, and subsidiaries
(collectively, "Calpine" or the "Company") is engaged in the generation of
electricity predominantly in the United States of America and Canada. 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. In the United States, the
Company has ownership interests in, and operates, gas-fired power generation and
cogeneration facilities, pipelines, geothermal steam fields and geothermal power
generation facilities. 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 addition, at June 30, 2005, the Company owned and operated a gas-fired power
cogeneration facility in the United Kingdom, but sold this facility on July 28,
2005. The Company markets electricity produced by its generating facilities to
utilities and other third party purchasers. Thermal energy produced by the
gas-fired power cogeneration facilities is primarily sold to industrial users.
The Company offers to third parties energy procurement, liquidation and risk
management services, combustion turbine component parts and repair and
maintenance services world-wide. The Company also provides engineering,
procurement, construction management, commissioning and O&M services. The
Company previously owned oil and gas exploration and production assets in the
United States and Canada. In September 2004, the Company sold all of its
Canadian and a portion of its United States oil and gas assets and, on July 7,
2005, the Company completed the sale of substantially all of its remaining oil
and gas exploration and production assets.
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 SEC. 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, 2004,
included in the Company's Current Report on Form 8-K dated December 31, 2004,
filed with the SEC on October 17, 2005. The results for interim periods are not
necessarily indicative of the results for the entire year.
Reclassifications -- Certain prior years' amounts in the Consolidated
Condensed Financial Statements have been reclassified to conform to the 2005
presentation. This includes a reclassification to separately disclose
transmission sales revenue (formerly in other revenue). The Company has also
made restatements for discontinued operations. See Note 8 for more information.
In addition, the Company had certain reclassifications on its Consolidated
Condensed Statement of Cash Flows to conform to the 2005 presentation.
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 and operation), provision for income taxes, fair value
calculations of derivative instruments and associated reserves, capitalization
of interest, impairment assessments, primary beneficiary determination for the
Company's investments in VIEs, 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 (prior to the July 2005
disposition).
Cash and Cash Equivalents -- The Company considers all highly liquid
investments with an original maturity of three months or less to be cash
equivalents. The carrying amount of these instruments approximates fair value
because of their short maturity.
The Company has certain project finance facilities and lease agreements
that establish segregated cash accounts. These accounts have been pledged as
security in favor of the lenders to such project finance facilities, and the use
of certain cash balances on deposit in such accounts with our project financed
- 11 -
subsidiaries is limited to the operations of the respective projects. At
September 30, 2005, and December 31, 2004, $423.5 million and $284.4 million,
respectively, of the cash and cash equivalents balance that was unrestricted was
subject to such project finance facilities and lease agreements. In addition, at
September 30, 2005, and December 31, 2004, $50.9 million and $232.4 million,
respectively, of the Company's cash and cash equivalents was held in bank
accounts outside the United States.
Restricted Cash -- The Company is required to maintain cash balances that
are restricted by provisions of its debt agreements, lease agreements and
regulatory agencies. These amounts are held by depository banks in order to
comply with the contractual provisions requiring reserves for payments such as
for debt service, rent service, major maintenance and debt repurchases. Funds
that can be used to satisfy obligations due during the next twelve months are
classified as current restricted cash, with the remainder classified as
non-current restricted cash. Restricted cash is generally invested in accounts
earning market rates; therefore the carrying value approximates fair value. Such
cash is excluded from cash and cash equivalents in the consolidated statements
of cash flows.
In addition, in connection with disputes concerning the use of proceeds
from the Company's sales of Saltend and of its remaining oil and gas assets (see
Notes 8 and 12 for more information) approximately $609.2 million of the net
proceeds of such sales has been classified as Current restricted cash as of
September 31, 2005, until these disputes are resolved.
Effective Tax Rate -- For the three months ended September 30, 2005, the
effective rate from continuing operations increased to (7.8)% as compared to
(237.6)% for the three months ended September 30, 2004. For the nine months
ended September 30, 2005, and 2004, the effective tax rate was 21.3% and 42.6%,
respectively. The tax rates on continuing operations for the three and nine
months ended September 30, 2005, were adversely affected due to a valuation
allowance recorded against certain NOL deferred tax assets associated with CCFC
LLC in the amount of approximately $143.4 million. The variance in the effective
tax rate for the three months ended September 30, 2005 compared to the same
period in 2004 was significantly impacted by the nominal absolute dollar amount
of the Company's pre-tax income (loss) in each period. For the three months
ended September 30, 2004, the Company's pre-tax income from continuing
operations was $8.6 million. Therefore, due to the near break-even absolute
value of this amount, the tax benefit for the period translated into a high tax
rate percentage, even though the benefit was only $20.3 million. Conversely, for
the three months ended September 30, 2005, pre-tax loss from continuing
operations was $224.9 million and the tax provision for the period was only
$17.5 million. Excluding the effects of the valuation allowance associated with
CCFC LLC, the Company would have recognized a tax benefit of $125.9 million for
the three months ended September 30, 2005 resulting in an effective tax rate of
56.0%. While this tax benefit (excluding the effects of CCFC LLC) was $105.6
million higher than the tax benefit recognized for the three months ended
September 30, 2004, the effective tax rate was significantly higher for the
three months ended September 30, 2004 due to the nominal absolute value of
pre-tax income from continuing operations. Also, the tax rates on continuing
operations for the three and nine months ended September 30, 2004, have been
restated in accordance with FIN 18, "Accounting for Income Taxes in Interim
Periods - an Interpretation of APB Opinion No. 28," as amended, to reflect the
effects of classifying the sale of the Company's Canadian and U.S. Rocky
Mountain oil and gas assets, and the Saltend, Morris and Ontelaunee power plants
as discontinued operations due to the Company's commitment to a plan of
divesture in the second quarter of 2005. See Note 8 for more information. This
effective tax rate on continuing operations is based on the consideration of
estimated year-end earnings in estimating the quarterly effective rate, the
effect of permanent non-taxable items and establishment of valuation allowances
on certain deferred tax assets.
Preferred Interests -- As outlined in SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity," the
Company classifies preferred interests that embody obligations to transfer cash
to the preferred interest holder, 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.
Long-Lived Assets and Impairment Evaluation -- In accordance with SFAS No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the
Company evaluates the impairment of long-lived assets, including construction
and development projects by first estimating projected undiscounted pre-interest
expense and pre-tax expense cash flows whenever events or changes in
circumstances indicate that the carrying amounts of such assets may not be
recoverable. The significant assumptions that the Company uses in its
undiscounted future cash flow estimates include the future supply and demand
relationships for electricity and natural gas, the expected pricing for those
and that the Company will hold these assets over their depreciable lives
- 12 -
commodities and the resultant spark spreads in the various regions where the
Company generates and that the Company will hold these assets over their
depreciable lives. In the event such cash flows are not expected to be
sufficient to recover the recorded value of the assets, the assets are written
down to their estimated fair values. Certain of the Company's generating assets
are located in regions with depressed demands and market spark spreads. The
Company's forecasts assume that spark spreads will increase in future years in
these regions as the supply and demand relationships improve. There can be no
assurance that this will occur. See Note 8 for a discussion of the impairment
charge related to Ontelaunee, which met the held-for-sale criteria as of
September 30, 2005, and was subsequently sold on October 6, 2005.
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"
as amended by SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure." SFAS No. 148 amended 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 APB
Opinion No. 25, "Accounting for Stock Issued to Employees," and its related
implementation guidance 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 provided two additional transition
options to report the change in accounting principle--the modified prospective
method and the retroactive restatement method. Additionally, SFAS No. 148
amended 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 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 EPS as presented in the table below, as
if SFAS No. 123 accounting had been applied to all prior periods presented
within its financial statements until SFAS No. 123-R (discussed below) is
adopted in January 2006. As disclosed in the table below, the Company's
prospective 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, 2005 and 2004, had the Company applied
the accounting provisions of SFAS No. 123 to its financial statements in years
prior to its adoption of SFAS No. 123 (in thousands, except per share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2005 2004 2005 2004
----------- ----------- ----------- -----------
Net income (loss)
As reported........................................................... $ (216,689) $ 141,125 $ (683,879) $ 41,235
Pro Forma............................................................. (216,751) 140,102 (684,678) 37,288
Income (loss) per share data:
Basic earnings per share
As reported......................................................... $ (0.45) $ 0.32 $ (1.49) $ 0.10
Pro Forma........................................................... (0.45) 0.32 (1.49) 0.09
Diluted earnings per share
As reported......................................................... $ (0.45) $ 0.32 $ (1.49) $ 0.10
Pro Forma........................................................... (0.45) 0.31 (1.49) 0.09
Stock-based compensation cost, net of tax,
included in income (loss), as reported................................ $ 2,711 $ 3,308 $ 9,963 $ 9,388
Stock-based compensation cost, net of tax,
included in income (loss), pro forma.................................. 2,773 4,331 10,762 13,335
New Accounting Pronouncements
SFAS No. 123-R
In December 2004, FASB issued SFAS No. 123 (revised 2004), "Share Based
Payments." This statement, referred to as SFAS No. 123-R, revises SFAS No. 123,
and supersedes APB Opinion No. 25 and its related implementation guidance. This
statement requires a public entity to measure the cost of employee services
received in exchange for an award of equity instruments based on the grant-date
fair value of the award (with limited exceptions), which must be recognized over
the requisite service period (usually the vesting period) during which an
employee is required to provide service in exchange for the award. The statement
applies to all share-based payment transactions in which an entity acquires
goods or services by issuing (or offering to issue) its shares, share options,
or other equity instruments or by incurring liabilities to an employee or other
supplier (a) in amounts based, at least in part, on the price of the entity's
shares or other equity instruments or (b) that require or may require settlement
by issuing the entity's equity shares or other equity instruments.
- 13 -
The statement requires the accounting for any excess tax benefits to be
consistent with the existing guidance under SFAS No. 123, which provides a
two-transaction model summarized as follows:
o If settlement of an award creates a tax deduction that exceeds
compensation cost, the additional tax benefit would be recorded as a
contribution to paid-in-capital.
o If the compensation cost exceeds the actual tax deduction, the
write-off of the unrealized excess tax benefits would first reduce any
available paid-in capital arising from prior excess tax benefits, and
any remaining amount would be charged against the tax provision in the
income statement.
The Company is still evaluating the impact of adopting and subsequently
accounting for excess tax benefits under the two-transaction model described in
SFAS No. 123, but does not expect its consolidated net income, cash flows or
financial position to be materially affected upon adoption of SFAS No. 123-R on
January 1, 2006.
The statement also amends SFAS No. 95, "Statement of Cash Flows," to
require that excess tax benefits be reported as a financing cash inflow rather
than as an operating cash inflow. However, the statement does not change the
accounting guidance for share-based payment transactions with parties other than
employees provided in SFAS No. 123 as originally issued and EITF Issue No.
96-18, "Accounting for Equity Instruments That Are Issued to Other Than
Employees for Acquiring, or in Conjunction with Selling, Goods or Services."
Further, this statement does not address the accounting for employee share
ownership plans, which are subject to AICPA Statement of Position 93-6,
"Employers' Accounting for Employee Stock Ownership Plans."
The statement applies to all awards granted, modified, repurchased, or
cancelled after January 1, 2006, and to the unvested portion of all awards
granted prior to that date. Public entities that used the fair-value-based
method for either recognition or disclosure under SFAS No. 123 may adopt SFAS
123-R using a modified version of prospective application pursuant to which
compensation cost for the portion of awards for which the employee's requisite
service has not been rendered, which awards are outstanding as of January 1,
2006, must be recognized as the requisite service is rendered on or after that
date. The compensation cost for that portion of those awards shall be based on
the original grant-date fair value of those awards as calculated for recognition
under SFAS No. 123. The compensation cost for those earlier awards shall be
attributed to periods beginning on or after January 1, 2006 using the
attribution method that was used under SFAS No. 123. Furthermore, the method of
recognizing forfeitures must now be based on an estimated forfeiture rate and
can no longer be based on forfeitures as they occur.
Adoption of SFAS No. 123-R is not expected to materially impact the
Company's consolidated results of operations, cash flows or financial position,
due to the Company's prior adoption of SFAS No. 123 as amended by SFAS No. 148,
"Accounting for Stock-Based Compensation -- Transition and Disclosure" on
January 1, 2003. SFAS No. 148 allowed companies to adopt the fair-value-based
method for recognition of compensation expense under SFAS No. 123 using
prospective application. Under that transition method, compensation expense was
recognized in the Company's Consolidated Statement of Operations only for
stock-based compensation granted after the adoption date of January 1, 2003.
Furthermore, as we have chosen the multiple option approach in recognizing
compensation expense associated with the fair value of each option granted,
nearly 94% of the total fair value of the stock option is recognized by the end
of the third year of the vesting period, and therefore remaining compensation
expense associated with options granted before January 1, 2003, is expected to
be immaterial.
SFAS No. 128-R
FASB is expected to revise SFAS No. 128, "Earnings Per Share" to make it
consistent with International Accounting Standard No. 33, "Earnings Per Share,"
so that EPS computations will be comparable on a global basis. This new guidance
is expected to be issued by the end of 2005 and will require restatement of
prior periods diluted EPS data. 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 EPS.
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, FASB has indicated that any possibility of share settlement other than
in an event of bankruptcy will require a presumption of share settlement when
calculating diluted EPS. The Company's 2023 Convertible Notes and 2014
Convertible Notes contain provisions that would require share settlement in the
event of conversion under certain events of default, including but not limited
to a bankruptcy-related event of default. Additionally, the 2023 Convertible
Notes include a provision allowing the Company to meet a put with either cash or
shares of stock. The Company's 2015 Convertible Notes allow for share settlement
- 14 -
of the principal only in the case of certain bankruptcy-related events of
default. Therefore, a presumption of share settlement is required for the 2014
Convertible Notes and the 2023 Convertible Notes, but is not required for the
2015 Convertible Notes. The revised guidance will result in a significant
increase in the potential dilution to the Company's EPS, particularly when the
price of the Company's common stock is low, since SFAS No. 128-R requires that
the more dilutive of calculations be used considering both:
o normal conversion assuming a combination of cash and variable number
of shares; and
o conversion during events of default other than bankruptcy assuming
100% shares at the fixed conversion rate, or, in the case of 2023
Convertible Notes, meeting a put entirely with shares of stock.
SFAS No. 151
In November 2004, FASB issued SFAS No. 151, "Inventory Costs, an amendment
of ARB No. 43, Chapter 4." This statement amends the guidance in ARB No. 43,
Chapter 4, "Inventory Pricing," to clarify the accounting for abnormal amounts
of idle facility expense, freight, handling costs, and wasted material
(spoilage). Paragraph 5 of ARB 43, Chapter 4, previously stated that ". . .
under some circumstances, items such as idle facility expense, excessive
spoilage, double freight, and rehandling costs may be so abnormal as to require
treatment as current period charges. . . ." This statement requires those items
to be recognized as a current-period charge regardless of whether they meet the
criterion of "so abnormal." In addition, SFAS No. 151 requires that allocation
of fixed production overheads to the costs of conversion be based on the normal
capacity of the production facilities. The provisions of SFAS No. 151 are
applicable to inventory costs incurred during fiscal years beginning after June
15, 2005. Adoption of this statement did not materially impact the Company's
consolidated results of operations, cash flows or financial position.
SFAS No. 153
In December 2004, FASB issued SFAS No. 153, "Exchanges of Nonmonetary
Assets." This statement eliminates the exception in APB Opinion No. 29,
"Accounting for Nonmonetary Transactions" for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. It requires exchanges
of productive assets to be accounted for at fair value, rather than at carryover
basis, unless (1) neither the asset received nor the asset surrendered has a
fair value that is determinable within reasonable limits or (2) the transaction
lacks commercial substance (as defined). A nonmonetary exchange has commercial
substance if the future cash flows of the entity are expected to change
significantly as a result of the exchange.
The new statement will not apply to the transfers of interests in assets in
exchange for an interest in a joint venture and amends SFAS No. 66, "Accounting
for Sales of Real Estate" to clarify that exchanges of real estate for real
estate should be accounted for under APB Opinion No. 29. It also amends SFAS No.
140, to remove the existing scope exception relating to exchanges of equity
method investments for similar productive assets to clarify that such exchanges
are within the scope of SFAS No. 140 and not APB Opinion No. 29. SFAS No. 153 is
effective for nonmonetary asset exchanges occurring in fiscal periods beginning
after June 15, 2005. Adoption of this statement did not materially impact the
Company's consolidated results of operations, cash flows or financial position.
SFAS No. 154
In May 2005, FASB issued SFAS No. 154, "Accounting Changes and Error
Corrections." This statement replaces APB Opinion No. 20, "Accounting Changes,"
and FASB Statement No. 3, "Reporting Accounting Changes in Interim Financial
Statements," and changes the requirements for the accounting for and reporting
of a change in accounting principle. SFAS No. 154 applies to all voluntary
changes in accounting principle. APB Opinion No. 20 previously required that
most voluntary changes in accounting principle be recognized by including in net
income for the period of the change the cumulative effect of changing to the new
accounting principle. SFAS No. 154 requires retrospective application to prior
periods' financial statements of changes in accounting principle, unless it is
impracticable to determine either the period-specific effects or the cumulative
effect of the change. When it is impracticable to determine the cumulative
effect of applying a change in accounting principle to all prior periods, SFAS
No. 154 requires that the new accounting principle be applied as if it were
adopted prospectively from the earliest date practicable.
SFAS No. 154 also requires that a change in depreciation, amortization, or
depletion method for long-lived, nonfinancial assets be accounted for as a
change in accounting estimate effected by a change in accounting principle. SFAS
No. 154 is effective for fiscal years beginning after December 15, 2005.
Adoption of this statement is not expected to materially impact the Company's
consolidated results of operations, cash flows or financial position.
- 15 -
EITF Issue No. 03-13
At the November 2004 EITF meeting, the final consensus was reached on EITF Issue
No. 03-13, "Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in
Determining Whether to Report Discontinued Operations." EITF Issue No. 03-13 is
effective prospectively for disposal transactions entered into after January 1,
2005, and 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. The Company
has applied the model outlined in EITF Issue No. 03-13 in its evaluation of the
September 2004 sale of the Canadian and U.S. Rocky Mountain oil and gas assets,
the July 2005 sales of the Company's remaining oil and gas assets and Saltend
facility, the sale of the Morris facility in August 2005 and the sale of the
Ontelaunee facility in October 2005 (which met the criteria necessary to be
classified as held-for-sale at September 30, 2005), in determining whether or
not the cash flows related to these components have been or will be permanently
eliminated from the ongoing operations of the Company.
3. Strategic Initiative
The Company's business is capital intensive. Its ability to capitalize on
growth opportunities and to service the debt it incurred to construct and
operate its current fleet of power plants is dependent on the continued
availability of capital. The availability of such capital in today's environment
remains uncertain. To date, the Company has obtained cash from its operations;
borrowings under credit facilities; issuances of debt, equity, preferred
securities, convertible and contingent convertible securities; proceeds from
sale/leaseback transactions; sale or partial sale of certain assets; prepayments
received for power sales; contract monetizations; and project financings. The
Company has utilized this cash to fund operations, service, repay or refinance
debt obligations, fund acquisitions, develop and construct power generation
facilities, finance capital expenditures, support hedging, balancing,
optimization and trading activities, and meet other cash and liquidity needs.
While the Company has been able to access the capital and bank credit
markets since 2002, it has been on significantly different terms than before. In
particular, the senior working capital facilities and term loan financings
entered into, and the majority of the debt securities offered and sold by the
Company have been secured by certain of the Company's assets and subsidiary
equity interests. The Company has also provided security to support prepaid
commodity transactions and, as the Company's credit ratings have been
downgraded, it has been required to post collateral to support its hedging,
balancing and optimization activities. In the aggregate, the average interest
rate on the Company's new debt instruments, especially on recent issuances of
subsidiary preferred stock and on debt incurred to refinance existing debt, has
been higher. The terms of capital available now and in the future may not be
attractive to the Company or its access to the capital markets may otherwise
become restricted. 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 the Company's control. Consistent with the Company's strategic
initiative announced in May 2005, it expects to rely to a greater extent than in
the past on asset sales to reduce debt and related interest expense and to
improve its liquidity position.
At September 30, 2005, the Company had working capital of $520.8 million
which increased approximately $242.7 million from December 31, 2004. The
increase was primarily due to increases of $494.6 million, $513.4 million, and
$379.5 million in accounts receivable, restricted cash, and current derivative
assets, respectively, offset by increases of $212.1 million, $249.4 million and
$618.1 million in accounts payable, Senior Notes, current portion and current
derivative liabilities, respectively, from December 31, 2004, to September 30,
2005. The increase in accounts receivable period over period was primarily due
to the significant increase in power prices during the three-month period ended
September 30, 2005, and to a lesser extent, an increase in megawatt hours sold
(due to additional generating capacity). Restricted cash increased primarily due
to the addition of $607.5 in remaining net proceeds from the sale of Saltend and
the Company's remaining oil and gas assets in July 2005. The Company's current
derivative assets and liabilities increased significantly primarily as a result
of significantly higher electricity and natural gas prices at the end of the
third quarter in 2005. Cash flow used in operating activities during the
nine-month period ended September 30, 2005 was $408.0 million and is expected to
continue to be negative at least for the near term and possibly longer. On
September 30, 2005, our cash and cash equivalents on hand totaled $843.1
million. The current portion of restricted cash totaled $1,106.7 million. See
Note 2 for more information on the Company's cash and cash equivalents and
restricted cash.
Satisfying all obligations under the Company's outstanding indebtedness,
and funding anticipated capital expenditures and working capital requirements
for the next twelve months presents the Company with several challenges as cash
requirements are expected to exceed the sum of cash on hand permitted to be used
to satisfy such requirements and cash from operations. Additionally, the Company
- 16 -
has significant near-term maturities of debt in periods subsequent to the next
twelve months including $1.4 billion in 2006 (including use of proceeds
obligations described in Note 7), $1.9 billion in 2007 and $1.4 billion in 2008
(see Note 7 for further discussion of future maturities and other matters
impacting the Company's debt). Accordingly, the Company has in place a strategic
initiative, as discussed further below, which includes possible sales or
monetizations of certain of its assets. Whether the Company will have sufficient
liquidity will depend, in part, on the success of that program. No assurance can
be given that the program will be successful. If it is not successful,
additional asset sales, refinancings, monetizations and other items beyond those
included in the strategic initiative would likely need to be made or taken,
depending on market conditions. The Company's ability to reduce debt will also
depend on its ability to repurchase debt securities through open market and
other transactions, and the principal amount of debt able to be repurchased will
be contingent upon market prices and other factors. Even if the program is
successful, there can be no assurance that the Company will be able to continue
work on its projects in development and suspended construction that have not
successfully obtained project financing, and it could possibly incur substantial
impairment losses as a result. In addition, even if the program is successful,
until there are significant sustained improvements in spark spreads, the Company
expects that it will not have sufficient cash flow from operations to repay all
of its indebtedness at maturity or to fund its other liquidity needs. The
Company expects that it will need to extend or refinance all or a portion of its
indebtedness on or before maturity. While the Company currently believes that it
will be successful in repaying, extending or refinancing all of its indebtedness
on or before maturity, there can be no assurance that it will be able to do so
on attractive terms or at all.
As part of the Company's efforts to improve its financial strength, the
Company announced a strategic initiative in May 2005 aimed at:
o Optimizing the value of the Company's core North American power plant
portfolio by selling certain power and natural gas assets to reduce
debt and lower annual interest cost, and to increase cash flow in
future periods. At September 30, 2005, the Company had completed the
sales of Saltend in the United Kingdom, Morris in Illinois and its
interest in Grays Ferry in Pennsylvania. Additionally, in October 2005
the Company completed the sale of Ontelaunee and in July 2005
completed the sale of substantially all of its remaining oil and
natural gas assets. The Company is also in discussions with potential
buyers for, or is considering, the sale of additional assets. See
Notes 8 and 15 for further information on these transactions.
o Taking actions to decrease operating and maintenance costs and
lowering fuel costs to improve the operating performance of the
Company's power plants, which would boost operating cash flow and
liquidity. In addition, to further reduce costs, the Company has
temporarily shut down two power plants and is considering others with
negative cash flow, until market conditions warrant starting back up,
to further reduce costs. See Note 12 for a discussion of the
restructuring of certain LTSAs.
o Reducing collateral requirements. On September 8, 2005, the Company
and Bear Stearns announced an agreement to form a new energy marketing
and trading venture to develop a third party customer business focused
on physical natural gas and power trading and related structured
transactions. Regulatory approval for this new entity was received on
October 31, 2005, and it is anticipated that operations will begin in
the fourth quarter of 2005. The transaction will include a $350
million credit intermediation agreement between CalBear, a new
subsidiary of Bear Stearns, and CES. It is anticipated that this
credit intermediation agreement will, among other things, positively
impact Calpine's working capital position by making possible the
return of cash and LCs currently posted as collateral.
o Reducing total debt, net of new construction financings, by more than $3
billion from debt levels at year-end 2004, which the Company estimates would
provide $275 million of annual interest savings. Calpine continues to advance
its May 2005 strategic initiative aimed at optimizing its power plant portfolio,
reducing debt and enhancing the Company's financial strength. While the company
continues to make progress toward its goal of reducing total debt by more than
$3 billion by year-end 2005 and achieving an estimated $275 million of annual
interest savings, the timing of accomplishing this goal may be delayed into
2006. The cash and other consideration needed to reduce debt by that amount will
be a function of the timing of asset sales, the Company's ability to use
proceeds of such sales to reduce debt (we are currently involved in various
litigations with the holders of certain series of our outstanding secured and
unsecured bonds as described in Note 12 of the Notes to Consolidated Condensed
Financial Statements), the prices at which the Company is able to repurchase
debt, and other factors. At September 30, 2005, total consolidated debt was
$17.2 billion, a reduction of $0.9 billion from the $18.1 billion level at March
31, 2005, before the strategic initiative was announced. Excluding the effect of
new construction financing of $178.7 million, the Company has reduced debt by
approximately $1.1 billion. However, regardless of whether or not the specific
$3 billion debt reduction
- 17 -
goal can be achieved by December 31, 2005, the Company remains
committed to achieving that goal as soon as practicable.
In addition, as noted above, the Company seeks to identify opportunities to
capture value in the skills and knowledge that it has developed, not only to
improve the operating performance of its facilities but also to develop new
sources of revenues, for example, by utilizing its hedging and optimization
skills to develop the CalBear business and by expanding its third-party
combustion turbine component parts and retail and maintenance services
businesses. The Company also actively explores possible alternative sources of
natural gas (such as LNG and Alaskan pipeline projects) to increase the natural
gas supply in the continental United States, as well as other sources of fuel
for its natural gas-fired generation facilities, such as projects to convert pet
coke, an oil refinery waste product, into gas suitable for combustion in its gas
turbines. There can be no assurance that the Company will be successful in
developing such alternative or additional sources of fuel in the near term or
otherwise.
While there can be no assurance that the Company will be successful in
achieving the goals of its strategic initiative and meeting its financing
obligations, progress in the quarter ended September 30, 2005, included the
following:
o Issued $150.0 million of Class A Redeemable Preferred Shares due 2006
through its indirect subsidiary, CCFC LLC, which is an indirect parent
of CCFC I, which owns a portfolio of six operating natural gas-fired
power plants (not including Ontelaunee, which met the held for sale
criteria as of September 30, 2005) with the generation capacity of
more than 3,600 megawatts. The Redeemable Preferred Shares bear an
initial dividend rate of LIBOR plus 950 basis points and were
redeemable in whole or in part at any time by CCFC LLC at par plus
accrued dividends. The Redeemable Preferred Shares were repurchased in
full on October 14, 2005.
o Completed the sale of substantially all of its remaining oil and gas
exploration and production properties and assets for $1.05 billion,
less adjustments, transaction fees and expenses, and less
approximately $75 million to reflect the value of certain oil and gas
properties for which the Company was unable to obtain consents to
assignment prior to closing. Certain of the consents have been
received subsequent to September 30, 2005, and the remaining consents
are expected to be received by December 31, 2005. As further discussed
in Note 12, the Company initiated a lawsuit seeking access to blocked
proceeds remaining from this sale.
o Completed the sale of Saltend, a 1,200-MW power plant in Hull,
England, generating total gross proceeds of $862.9 million. Of this
amount, approximately $647.1 million was used to redeem the $360.0
million Two-Year Redeemable Preferred Shares issued by our Calpine
Jersey I subsidiary on October 26, 2004, and the $260.0 million
Redeemable Preferred Shares issued by our Calpine Jersey II subsidiary
on January 31, 2005, including interest and termination fees of $16.3
million and $10.8 million, respectively. As discussed in Note 12,
certain bondholders initiated a lawsuit concerning the use of the
proceeds remaining from the sale of Saltend.
o Completed the sale of the Company's Inland Empire Energy Center
development project to GE, for approximately $30.9 million. The
project will be financed, owned and operated by GE and will be used to
launch GE's most advanced gas turbine technology, the "H System (TM)."
The Company will manage plant construction, market the plant's output,
and manage its fuel requirements. The Company has an option to
purchase the facility in years seven through fifteen following the
commercial operation date and GE can require the Company to purchase
the facility for a limited period of time in the fifteenth year, all
subject to satisfaction of various terms and conditions. If the
Company purchases the facility under the call or put, GE will continue
to provide critical plant maintenance services throughout the
remaining estimated useful life of the facility. Because of continuing
involvement related to the purchase option and put, the Company
deferred the gain generated from the sale of the development company
of approximately $10 million until the call or put option is either
exercised or expires.
o Completed the sale of Company's 50% interest in the 175-MW Grays Ferry
power plant for gross proceeds of $37.4 million. The Company recorded
an impairment charge of $18.5 million related to its interest in this
facility in the quarter ended June 30, 2005.
o Completed the sale of the Company's 156-MW Morris power plant for
approximately $84.5 million. In the three months ended June 30, 2005,
the Company recorded a $106.2 million impairment charge related to its
commitment to a plan of divesture of this facility which was
reclassified to discontinued operations in the three month period
ending September 30, 2005, upon completion of the sale.
- 18 -
o Repurchased approximately $138.9 million of First Priority Notes
pursuant to a tender offer. Following the completion of the tender
offer, the Company now has approximately $641.5 million aggregate
principal amount of First Priority Notes outstanding.
o Announced a 15-year Master Products and Services Agreement with GE,
which is expected to lower operating costs in the future. As a result
of 9 GE LTSA cancellations, the Company recorded $33.3 million in
charges in the quarter ended June 30, 2005.
o Signed an agreement with Siemens-Westinghouse to restructure the
long-term relationship, which is expected to provide additional
flexibility to self-perform maintenance work in the future.
Additionally, subsequent to September 30, 2005, the Company completed the
following transactions (see Note 15 for more information):
o Completed the sale of the Company's 561-MW Ontelaunee power plant for
$225.0 million, less transaction costs and working capital adjustments
of approximately $125.0 million. The Company recorded an impairment
charge of $136.8 million as of September 30, 2005 which is reflected
in discontinued operations. The sale of Ontelaunee closed October 6,
2005. See Notes 5 and 8 for more information. CCFC I made offers to
purchase its outstanding debt with the proceeds of the Ontelaunee sale
in accordance with the instruments governing such debt. The offers
have expired, and none of the holders of such debt elected to have
their debt repurchased.
o Received funding on CCFC LLC's $300.0 million offering of Redeemable
Preferred Shares due 2011.
o Repurchased the CCFC LLC $150.0 million Class A Redeemable Preferred
Shares due 2006.
While the Company has recognized a pre-tax gain overall on asset sales
completed during the three and nine months ended September 30, 2005, the Company
has recognized significant impairment charges or losses with respect to certain
asset sales, including the sale of the Morris facility, as well as the sale of
the Ontelaunee facility in October 2005. The Company is considering the sale of
additional assets in connection with its strategic initiative program, and it is
possible that some or all of the additional asset sales contemplated could lead
to material impairment charges or losses upon sale.
The sale of assets to reduce debt and lower annual interest costs is
expected to materially lower the Company's revenues, spark spread and gross
profit (loss) and the final mix of assets actually sold will determine the
degree of impact on operating results. While lowering debt, the accomplishment
of the strategic initiative program, in and of itself, will likely not lead to
improvement in certain measures of interest and principal coverage without
significant improvement in market conditions. The amount of offsetting future
interest savings will be a function of the principal amount of debt retired and
the interest rate born by such debt. The amount that the Company will spend to
reduce debt will depend on the market price of such debt and other factors, and
the final net future earnings impact of the initiatives is still uncertain.
4. Available-for-Sale Debt Securities
On September 30, 2004, the Company repurchased $115.0 million in par value
of HIGH TIDES III preferred securities for cash of $111.6 million. Due to the
deconsolidation of Calpine Capital Trust III, the issuer of the HIGH TIDES III
preferred securities, upon the adoption of FIN 46 as of December 31, 2003, and
the terms of the underlying convertible debentures issued by Calpine to the
Trust, the repurchased HIGH TIDES III preferred securities could not be offset
against the convertible subordinated debentures and, accordingly, the Company
accounted for the repurchased HIGH TIDES III preferred securities as
available-for-sale securities. On July 13, 2005, the Company completed the
redemption of all of the outstanding HIGH TIDES III preferred securities and of
the underlying convertible debentures. Accordingly, the HIGH TIDES III preferred
securities repurchased by the Company are no longer outstanding, and the Company
has no available-for-sale debt securities recorded in the Consolidated Condensed
Balance Sheet at September 30, 2005. See Note 7 for additional information.
- 19 -
5. Property, Plant and Equipment, Net and Capitalized Interest
As of September 30, 2005, and December 31, 2004, the components of
property, plant and equipment, net, stated at cost less accumulated depreciation
and depletion are as follows (in thousands):
September 30, December 31,
2005 2004
------------- ------------
Buildings, machinery, and equipment ........................................ $ 16,521,482 $ 14,615,907
Pipelines .................................................................. 82,398 90,625
Geothermal properties ...................................................... 481,255 474,869
Other ...................................................................... 182,183 206,049
------------ ------------
17,267,318 15,387,450
Less: accumulated depreciation and depletion ............................... (1,798,377) (1,416,586)
------------ ------------
15,468,941 13,970,864
Land ....................................................................... 94,219 104,972
Construction in progress ................................................... 2,979,763 4,321,907
------------ ------------
Property, plant and equipment, net ......................................... $ 18,542,923 18,397,743
============ ============
Capital Spending -- Construction and Development
Construction and Development costs in process consisted of the following at
September 30, 2005 (in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP CIP Costs Equipment
-------- ---------- ---------- ---------- ----------
Projects in active construction (1) ...... 4 $ 803,004 $ 291,709 $ -- $ --
Projects in suspended construction ....... 3 1,130,364 391,505 -- --
Projects in advanced development ......... 10 721,381 545,458 89,942 --
Projects in suspended development ........ 4 309,928 77,624 36,397 --
Projects in early development ............ 2 -- -- 8,952 --
Other capital projects ................... NA 15,086 -- -- --
Unassigned equipment ..................... NA -- -- -- 67,691
---------- ---------- ---------- ----------
Total construction and development costs $2,979,763 $1,306,296 $ 135,291 $ 67,691
========== ========== ========== ==========
- ------------
<FN>
(1) There were a total of four consolidated projects in active construction at
September 30, 2005. Additionally, the Company has one project in active
construction that is recorded in unconsolidated investments and is not
included in the table above.
</FN>
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 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 four projects in active construction
are projected to come on line from November 2005 to November 2007. These
projects will bring on line approximately 1,247 MW of base load capacity (1,478
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. At September 30, 2005, the total projected costs to complete these
projects was $586.2 million.
Projects in Suspended Construction -- Work and capitalization of interest
on the three projects in suspended construction has been suspended or delayed
due to current market conditions. These projects would bring on line
approximately 1,769 MW of base load capacity (2,035 MW with peaking capacity).
The Company expects to finance the remaining $324.7 million projected costs to
complete these projects when construction resumes.
Projects in Advanced Development -- There were ten projects in advanced
development at September 30, 2005. These projects would bring on line
approximately 4,151 MW of base load capacity (5,361 MW with peaking capacity).
- 20 -
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 four projects for which
development activities are substantially complete but construction will not
commence until a PPA and financing are obtained. During the quarter, the Company
sold Inland Empire Energy Center, a project previously accounted for in advanced
development, to a third party and moved the Wawayanda project from advanced
development to suspended development. See Note 3 for more information on the
sale of Inland Empire to GE. The estimated cost to complete the remaining ten
projects in advanced development was approximately $2.6 billion at September 30,
2005. The Company's current plan is to finance these project costs as PPAs are
executed.
Suspended Development Projects --The Company has ceased capitalization of
additional development costs and interest expense on four 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 indicating that it is again highly
probable that the costs will be recovered through future operations. As is true
for all of the Company's projects, the suspended projects are reviewed for
impairment whenever there is an indication of potential reduction in a project's
fair value. Further, 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 their
recoverable value. The four projects in suspended development would bring on
line approximately 1,365 MW of base load capacity (1,555 MW with peaking
capacity). The estimated cost to complete these projects is approximately $837.6
million.
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 two projects and
include geothermal drilling costs and equipment purchases.
Other Capital Projects -- Other capital projects primarily consist of
enhancements to operating power plants, pipelines and geothermal resource and
facilities development, as well as software developed for internal use.
Unassigned Equipment -- As of September 30, 2005, the Company had made
progress payments on four turbines and other equipment with an aggregate
carrying value of $67.7 million. This unassigned equipment is classified on the
Consolidated Condensed 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.
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," 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)." The Company's qualifying assets include
CIP, certain pipelines under development, geothermal properties under
construction, certain costs for information systems development, construction
costs related to unconsolidated investments in power projects under
construction, and advanced stage development costs. For the three months ended
September 30, 2005 and 2004, the total amount of interest capitalized was $36.5
million and $86.6 million, respectively, including $7.8 million and $9.4
million, respectively, of interest incurred on funds borrowed for specific
construction projects and $28.7 million and $77.4 million, respectively, of
interest incurred on general corporate funds used for the advanced stages of
development and construction. For the nine months ended September 30, 2005 and
2004, the total amount of interest capitalized was $170.9 million and $296.9
million, respectively, including $30.4 million and $43.3 million, respectively,
of interest incurred on funds borrowed for specific construction projects and
$140.5 million and $253.6 million, respectively, of interest incurred on general
corporate funds used for construction. Upon commencement of plant operation,
capitalized interest, as a component of the total cost of the plant, is
amortized over the estimated useful life of the plant. The decrease in the
amount of interest capitalized during the three and nine months ended September
30, 2005, reflects the completion of construction for several power plants, the
suspension of certain of the Company's development and construction projects,
and a reduction in the Company's development and construction program in
general.
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
- 21 -
calculation of interest incurred on general corporate funds are the Company's
Senior Notes and term loans.
Impairment Evaluation -- All construction and development projects and
unassigned turbines are reviewed for impairment whenever there is an indication
of potential reduction in fair value. Equipment assigned to such projects is not
evaluated for impairment separately, as it is integral to the assumed future
operations of the project to which it is assigned. If it is determined that it
is no longer probable that the projects will be completed and all capitalized
costs recovered through future operations, the carrying values of the projects
would be written down to the recoverable value in accordance with the provisions
of SFAS No. 144. 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 held for use is impaired.
However, during the three month periods ending September 30, 2005 and 2004, and
the nine month periods ended September 30, 2005 and 2004, respectively, the
Company recorded to the "Equipment cancellation and impairment cost" line of the
Consolidated Condensed Statement of Operations $0.8 million and $7.8 million,
and $0.7 million and $10.2 million, respectively, in net losses in connection
with equipment cancellations, and it may incur further losses should it decide
to cancel more equipment contracts or sell unassigned equipment in the future.
In the event the Company were unable to obtain PPAs or project financing and
suspension or abandonment were to result, the Company could suffer substantial
impairment losses on such projects.
Based on an evaluation of the probability-weighted expected future cash
flows, giving consideration to the continued ownership and operation of the
Morris power plant or consummating the potential sale transaction at June 30,
2005, the Company determined that the carrying amount of the facility was
impaired due to the high probability of consummating the sale. As a result,
during the three months ended June 30, 2005, the Company recorded to the "Power
plant impairment" line of the Consolidated Condensed Statement of Operations a
$106.2 million impairment charge representing the difference between the
proposed sale price and the facility's book value at June 30, 2005. On August 2,
2005, the Company completed the sale of the facility for approximately $84.5
million in cash and reclassified the impairment charge to discontinued
operations. See Note 8 for more information on this sale.
At September 30, 2005, the Company had committed to a plan to divest the
Ontelaunee power plant. In accordance with SFAS No. 144, the Company recorded an
impairment charge of $136.8 million for the difference between the estimated
sale price (less estimated selling costs) and the facility's book value as of
September 30, 2005. This charge is reflected in discontinued operations in the
Consolidated Condensed Statement of Operations for the three and nine-month
periods ended September 30, 2005. The sale was completed on October 6, 2005. See
Notes 5 and 8 for a discussion of the Company's sale of the Ontelaunee power
plant.
See Note 6 for a discussion of the impairment charge in connection with the
Grays Ferry power plant and Note 3 for a discussion of potential additional
material impairment charges arising from the possible sale of additional assets.
6. Unconsolidated Investments
The Company's unconsolidated investments are integral to its operations.
The Company's joint venture investments were evaluated under FASB Interpretation
No. 46 "Consolidation of Variable Interest Entities - An Interpretation of ARB
51" as amended, to determine which, if any, entities were VIEs. Based on this
evaluation, the Company determined that Acadia PP, Valladolid, Grays Ferry,
Whitby and AELLC were VIEs, in which the Company held a significant variable
interest. However, all of the entities except for Acadia PP met the definition
of a business and qualified for the business scope exception provided in
paragraph 4(h) of FIN 46-R, and consequently were not subject to the VIE
consolidated model. Further, based on a qualitative and quantitative assessment
of the expected variability in Acadia PP, the Company was not the Primary
Beneficiary. Consequently, the Company continues to account for its joint
venture investments in accordance with APB Opinion No. 18, "The Equity Method of
Accounting For Investments in Common Stock" and FIN 35, "Criteria for Applying
the Equity Method of Accounting for Investments in Common Stock (An
Interpretation of APB Opinion No. 18)." However, in the fourth quarter of 2004,
the Company changed from the equity method to the cost method to account for its
investment in AELLC as discussed below.
Acadia PP is the owner of a 1,210-MW electric wholesale generation
facility, Acadia Energy Center, 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 from its equity investment at September 30, 2005, was
limited to the book value of its investment of approximately $215.7 million,
plus any loss that may accrue from a tolling agreement between Acadia PP and
CES.
- 22 -
Valladolid is the owner of the Valladolid III Energy Center, a 525-MW,
natural gas-fired energy center currently under construction at Valladolid,
Mexico in the Yucatan Peninsula. The facility will deliver electricity to CFE
under a 25-year power sales agreement. The project is a joint venture between
the Company and Mitsui, and Chubu, both headquartered in Japan. The Company owns
45% of the entity while Mitsui and Chubu each own 27.5%. Construction began in
May 2004 and the project is expected to achieve commercial operation in the
summer of 2006. The Company's maximum potential exposure to loss at September
30, 2005, was limited to the book value of its investment of approximately $82.7
million.
Grays Ferry is the owner of a 175-MW gas-fired cogeneration facility,
located in Pennsylvania and was 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, Cogen America, now
called Calpine Cogen, in December 1999. The Grays Ferry joint venture project
was part of the portfolio of assets owned by Cogen America. On July 8, 2005, the
Company completed the sale of the Grays Ferry power plant, in which it held 50%
interest, for gross proceeds of $37.4 million. In June 2005, the Company
recorded to the "Other expense (income), net" line of the Consolidated Condensed
Statement of Operations a $18.5 million impairment charge. This transaction did
not qualify as a discontinued operation under the guidance of SFAS No. 144,
which specifically excludes equity method investments from its scope, unless the
investment is part of a larger disposal group.
Whitby is the owner of a 50-MW 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 in September 2001, which included the
Whitby joint venture project. The Company's maximum potential exposure to loss
at September 30, 2005, was limited to the book value of its investment of
approximately $49.6 million.
AELLC is the owner of a 136-MW gas-fired cogeneration facility,
Androscoggin Energy Center, located in Maine and is a joint venture between the
Company, and affiliates of Wisvest Corporation and IP. The Company's involvement
in this VIE began with its acquisition of the independent power producer,
SkyGen, in October 2000. The AELLC joint venture was part of the portfolio of
assets owned by SkyGen. On November 3, 2004, a jury verdict was rendered against
AELLC in a breach of contract dispute with IP. The Company recorded its $11.6
million share of the award amount in the third quarter of 2004. On November 26,
2004, AELLC filed a voluntary petition for relief under Chapter 11 of the
Bankruptcy Code. As a result of the bankruptcy, the Company has lost significant
influence and control of the project and has adopted the cost method of
accounting for its investment in AELLC. Also, in December 2004 the Company
determined that its investment in AELLC, including outstanding notes receivable
and O&M receivable, was impaired and recorded a $5.0 million impairment charge.
The facility had third-party debt of $63.4 million outstanding as of December
31, 2004, primarily consisting of $60.3 million in construction debt. The debt
was non-recourse to Calpine Corporation. On April 12, 2005, AELLC sold three
fixed-price gas contracts to Merrill Lynch Commodities Canada, ULC, and used a
portion of the proceeds to pay down its remaining construction debt. As of
September 30, 2005, the facility had third-party debt outstanding of $3.1
million. See Note 12 for an update on this investment.
The following investments are accounted for under the equity method except
for Androscoggin Energy Center, which is accounted for under the cost method (in
thousands):
Ownership Investment Balance at
Interest as of --------------------------------
September 30, September 30, December 31,
2005 2005 2004
---------------- ------------- ------------
Acadia Energy Center .......................................... 50.0% $215,657 $214,501
Valladolid III Energy Center .................................. 45.0% 82,661 77,401
Grays Ferry Power Plant (1) ................................... 50.0% -- 48,558
Whitby Cogeneration (2) ....................................... 15.0% 49,615 32,528
Androscoggin Energy Center (3) ................................ 32.3% -- --
Other ......................................................... -- 125 120
-------- --------
Total unconsolidated investments ............................ $348,058 $373,108
======== ========
- ------------
<FN>
(1) On July 8, 2005, the Company completed the sale of the Grays Ferry power
plant. Please see the above paragraph for a discussion of this sale.
(2) Whitby is owned 50% by the Company but a 70% economic share in the
Company's ownership interest has been effectively transferred to CPLP
through a loan from CPLP to the Company's entity which holds the investment
interest in Whitby.
- 23 -
(3) Excludes certain Notes Receivable.
</FN>
The third-party debt on the books of the unconsolidated investments is not
reflected on the Company's balance sheet. At September 30, 2005, and December
31, 2004, third party investee debt was approximately $200.2 million and $133.9
million, respectively. Of these amounts, $3.1 million and $63.4 million,
respectively, relate to the Company's investment in AELLC, for which the cost
method of accounting was used. Based on the Company's pro rata ownership share
of each of the investments, the Company's share would be approximately $74.3
million and $46.6 million for the respective periods. These amounts include the
Company's share for AELLC of $1.0 million and $20.5 million, respectively. All
such debt is non-recourse to the Company. The increase in investee debt between
periods is primarily due to borrowings for the Valladolid III Energy Center
currently under construction.
The following details the Company's income and distributions from
unconsolidated investments (in thousands):
Income (Loss) from
Unconsolidated
Investments Distributions
---------------------- ---------------------
For the Nine Months Ended September 30,
---------------------------------------------
2005 2004 2005 2004
-------- -------- -------- --------
Acadia Energy Center ......................................... $ 14,052 $ 9,490 $ 12,896 $ 14,438
Aries Power Plant ............................................ -- (4,265) -- --
Grays Ferry Power Plant ...................................... (739) (2,436) -- --
Whitby Cogeneration .......................................... 1,608 870 3,768 1,515
Calpine Natural Gas Trust .................................... -- -- -- 6,127
Androscoggin Energy Center ................................... -- (16,680) -- --
Valladolid III Energy Center ................................. (213) -- -- --
Other ........................................................ (64) 7 198 183
-------- -------- -------- --------
Total ...................................................... $ 14,644 $(13,014) $ 16,862 $ 22,263
======== ======== ======== ========
Interest income on notes receivable from power projects (1) .. $ -- $ 840
-------- --------
Total ...................................................... $ 14,644 $(12,174)
======== ========
- ------------
<FN>
(1) At September 30, 2005, and December 31, 2004, notes receivable from power
projects represented an outstanding loan to AELLC, in the amounts of $4.0
million and $4.0 million, after impairment reserves, respectively.
</FN>
The Company provides for deferred taxes on its share of earnings.
Related-Party Transactions with Unconsolidated Investments
The Company and certain of its equity and cost 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:
O&M Agreements -- The Company operates and maintains the Acadia and
Androscoggin Energy Centers. 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.
Construction Management Services Agreements -- The Company provides
construction management services to the Valladolid III Energy Center. Payments
include reimbursement of costs, including the Company's internal personnel and
other costs.
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 AELLC, 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.
- 24 -
Gas Supply Agreement -- CES can be directed to supply gas to the
Androscoggin Energy Center 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
which are accounted for as leases. All of the other power marketing and gas
supply contracts are accounted for as purchases and sales.
The related party balances as of September 30, 2005 and December 31, 2004,
reflected in the accompanying Consolidated Condensed Balance Sheets, and the
related party transactions for the three and nine months ended September 30,
2005, and 2004, reflected in the accompanying Consolidated Condensed Statements
of Operations are summarized as follows (in thousands):
September 30, December 31,
2005 2004
------------- ------------
Accounts receivable.......................... $ 541 $ 765
Accounts payable............................. 5,679 9,489
Note receivable.............................. 4,037 4,037
Other receivables............................ 428 --
2005 2004
------------- ------------
For the Three Months Ended September 30,
Revenue...................................... $ 143 $ 40
Cost of revenue.............................. 17,962 25,504
Interest income.............................. -- 347
For the Nine Months Ended September 30,
Revenue...................................... $ 279 $ 953
Cost of revenue.............................. 72,820 89,623
Interest income.............................. -- 840
Gain on sale of assets....................... -- 6,240
7. Debt
Repurchase of $138.9 million of 9 5/8% First Priority Senior Secured Notes
due 2014 -- On July 12, 2005, pursuant to a tender offer in connection with the
sale of the Company's remaining oil and gas assets and the related use of
proceeds under the Company's indentures (see Notes 8 and 12 for more information
regarding this asset sale and the subsequent use of proceeds), the Company
repurchased for cash (at par) $138.9 million in principal amount of its 9 5/8%
First Priority Senior Secured Notes due 2014. Following the completion of the
tender offer, the Company has approximately $641.5 million aggregate principal
amount of First Priority Notes outstanding as of September 30, 2005.
As discussed in Note 12, the Collateral Trustee for the Company's Senior
Secured Noteholders informed the Company of disagreements purportedly raised by
certain holders of its First Priority Notes regarding the Company's reinvestment
of the proceeds from the sale of domestic gas assets. As a result of these
concerns, the Collateral Trustee informed the Company that they will be
withholding further withdrawals from the gas sale proceeds account until these
disagreements can be resolved. In addition, the Collateral Trustee has not
released liens on certain properties for which consents were received after the
closing of the sale and, accordingly, the Company has not received payment for
such properties. On September 26, 2005, the Company filed a lawsuit against the
Collateral Trustee and the Trustee for the First Priority Notes seeking access
to the proceeds in the gas sale proceeds account. See "Indenture and Debt and
Lease Covenant Compliance" below, and Note 12 for further discussion regarding
the use of the proceeds of the sale of the gas assets and the status of the
related legal matter.
Issuance of Mandatorily Redeemable Preferred Interest -- On August 12,
2005, the Company issued $150.0 million of Class A Redeemable Preferred Shares
due 2006 through its indirect subsidiary, CCFC LLC, which is an indirect parent
of CCFC I. CCFC I owns a portfolio of six operating natural gas-fired power
plants (not including Ontelaunee, which met the held for sale criteria as of
September 30, 2005) with the generation capacity of more than 3,600 megawatts.
The Redeemable Preferred Shares bear an initial dividend rate of LIBOR plus 950
basis points and may be redeemed in whole or in part at any time by the issuer
at par plus accrued dividends. The Redeemable Preferred Shares were repurchased
in full on October 14, 2005. Net proceeds of approximately $144.2 million from
the sale will be used in accordance with the Company's existing bond indentures.
- 25 -
Extinguishment of HIGH TIDES III -- On July 13, 2005, the Company repaid
the convertible debentures payable to Calpine Capital Trust III, the issuer of
the HIGH TIDES III preferred securities. The Trust then used the proceeds to
redeem the outstanding HIGH TIDES III preferred securities totaling $517.5
million, of which $115.0 million was held by Calpine. See Note 4 for additional
information regarding available-for-sale debt securities. The redemption price
paid per each $50 principal amount of HIGH TIDES III preferred securities was
$50 plus accrued and unpaid distributions to the redemption date in the amount
of $0.50. All rights of holders of the HIGH TIDES III preferred securities have
ceased, except the right of such holders to receive the redemption price, which
was deposited with The Depository Trust Company on July 13, 2005.
Senior Note Repurchases -- During the three months ended September 30,
2005, the Company repurchased Senior Notes in open market transactions totaling
$263.5 million in principal amount. The Company repurchased the Senior Notes for
cash of $233.9 million plus accrued interest as follows (in thousands):
Senior Notes Principal Cash Payment
- ------------ ----------------- ----------------
8 1/4% due 2005........................ $ 4,000.0 $ 3,985.0
10 1/2 % due 2006...................... 10,005.0 9,671.0
7 5/8% due 2006........................ 8,051.0 7,648.4
8 3/4% due 2007........................ 2,000.0 1,570.0
7 7/8% due 2008........................ 53,500.0 39,598.8
8 1/2% due 2008........................ 41,000.0 28,632.5
7 3/4% due 2009........................ 6,000.0 3,900.0
9 5/8% due 2014........................ 138,895.0 138,895.0
---------------- ----------------
Total repurchases................... $ 263,451.0 $ 233,900.7
================ ================
For the three months ended September 30, 2005, the Company recorded an
aggregate pre-tax gain of $15.5 million on the above debt repurchases and
extinguishment of HIGH TIDES III after the write-off of unamortized deferred
financing costs, legal fees and unamortized discounts.
Annual Debt Maturities -- The annual principal repayments or maturities of
notes payable and borrowings under lines of credit, preferred interests, capital
lease obligation, CCFC I financing, CalGen financing, construction/project
financing, convertible notes, and senior notes and term loans, as of September
30, 2005, are as follows (in thousands):
October through December 2005................................. $ 35,978
2006.......................................................... 1,427,080
2007.......................................................... 1,857,780
2008.......................................................... 1,374,781
2009.......................................................... 1,630,211
Thereafter.................................................... 11,058,266
--------------
Total debt.................................................... 17,384,096
(Discount) / Premium.......................................... (196,088)
--------------
Total....................................................... $ 17,188,008
==============
Due Due Total
October - December January - September Current
2005 2006 Debt (1)
------------------ ------------------- -----------
(In thousands)
10 1/2% Senior Notes Due 2006 .................................... $ -- $ 139,205 $ 139,205
6 5/8% Senior Notes Due 2006 ..................................... -- 102,194 102,194
6 7/8% Senior Notes Due 2007 ..................................... 3,125 9,375 12,500
Other scheduled debt maturities .................................. 32,853 283,505 316,358
Estimated debt repurchase obligation (2) ......................... 150,020 714,000 864,000
---------- ---------- ----------
$ 185,998 $1,248,279 $1,434,257
========== ========== ==========
- ------------
<FN>
(1) Excludes net discounts of $2,523.7
(2) See "Indenture and Debt and Lease Covenant Compliance" below for a
discussion of this obligation.
</FN>
Indenture and Debt and Lease Covenant Compliance -- The covenants in
certain of the Company's debt agreements currently impose restrictions on its
activities, including those discussed below:
- 26 -
Certain of the Company's indentures place conditions on its ability to
issue indebtedness if the Company's interest coverage ratio (as defined in those
indentures) is below 2:1. Currently, the Company's interest coverage ratio (as
so defined) is below 2:1. As such, the Company generally would not be allowed to
issue new debt, except for certain types of permitted debt, such as (i) new
indebtedness that refinances or replaces existing indebtedness and (ii)
non-recourse debt and preferred equity interests issued by the Company's
subsidiaries for purposes of financing certain types of capital expenditures,
including plant development, construction and acquisition costs and expenses. In
addition, if and so long as the Company's interest coverage ratio is below 2:1,
the Company's ability to invest in unrestricted subsidiaries and non-subsidiary
affiliates and make certain other types of restricted payments will be limited.
Moreover, certain of the Company's indentures will prohibit any further
investments in non-subsidiary affiliates if and for so long as its interest
coverage ratio (as defined therein) is below 1.75:1 and, as of September 30,
2005, such interest coverage ratio was below 1.75:1. The Company currently does
not expect this limitation on its ability to make investments in non-subsidiary
affiliates to have a material impact on its business.
Certain of the Company's indebtedness issued in the last half of 2004 was
incurred in reliance on provisions in certain of its existing indentures
pursuant to which the Company is able to incur indebtedness if, after giving
effect to the incurrence and the repayment of other indebtedness with the
proceeds therefrom, the Company's interest coverage ratio (as defined in those
indentures) is greater than 2:1. In order to satisfy the interest coverage ratio
requirement in connection with such issuances, the proceeds thereof were
required to be used to repurchase or redeem other existing indebtedness. As
previously reported in the Company's 2004 10-K and its Quarterly Reports on Form
10-Q for the first two quarters of 2005, the Company completed a substantial
portion of such repurchases during the fourth quarter of 2004 and the first six
months of 2005. The Company completed the remaining required repurchases,
spending approximately $248.4 million in the third quarter of 2005 to repurchase
debt, and has now fully satisfied this requirement. The amount the Company was
required to spend exceeded its estimate of $184.0 million because the required
principal amount of debt was repurchased at prices higher than originally
anticipated.
When the Company or one of its subsidiaries sells a significant asset or
issues preferred equity, the Company's indentures generally require that the net
proceeds of the transaction be used to make capital expenditures, to acquire
permitted assets or capital stock, or to repurchase or repay indebtedness, in
each case within 365 days of the closing date of the transaction. To the extent
that $50 million or more of such net proceeds are not so used, the Company is
required under the terms of its secured debt instruments to make an offer to
purchase its outstanding senior secured indebtedness up to the amount of the
unused net proceeds. This general requirement contains certain customary
exceptions, and, in the case of certain assets defined as "designated assets"
under some of the Company's indentures, including the gas portion of the
Company's oil and gas assets sold in July 2005, there are additional provisions
discussed further below that apply to the use of the proceeds of a sale of those
assets. In light of these requirements, and after taking into account the amount
of capital expenditures currently budgeted for the remainder of 2005 and
forecasted for 2006, the Company anticipates that, in the fourth quarter of 2005
and the first three quarters of 2006, it will need to use approximately $195.5
million and $668.5 million, respectively, of the remaining net proceeds from
four series of preferred equity issued by subsidiaries of the Company and three
asset sale transactions, all completed prior to September 30, 2005, to
repurchase or repay indebtedness or acquire assets or capital stock. The Company
has, subsequent to September 30, 2005, fulfilled the portion of this obligation
as required to be completed in the fourth quarter of 2005. Accordingly, assuming
that the Company would fulfill these remaining obligations by repurchasing
indebtedness, an aggregate amount of approximately $714.0 million of Senior
notes and term loan, net of current portion, and $150.0 million of Preferred
interest, net of current portion, related to this use of net proceeds
requirement has been classified as Senior Notes, current portion, and Preferred
interest, current portion, respectively, on the Company's Consolidated Condensed
Balance Sheet as of September 30, 2005. The actual amount of the net proceeds
that will be required to be used to repurchase or repay debt will depend, among
other things, upon the actual amount of the net proceeds that is used to make
capital expenditures or acquire other assets or capital stock, which may be more
or less than the amount currently budgeted and/or forecasted. This amount
includes $207.5 million of the net proceeds of the sale of Saltend. As discussed
in Note 12, certain bondholders filed a lawsuit concerning the use of the
proceeds from the sale of Saltend. In connection with that lawsuit, the Company
is prohibited from repatriating this amount due to an order of the Court in that
matter requiring such proceeds to be held at or in the control of CCRC. To the
extent repatriation of such net proceeds is ultimately permitted, the
repatriated net proceeds will be applied pursuant to the use of proceeds
provisions of the Company's indentures described herein as if the sale of
Saltend had occurred on the date of repatriation.
In addition, the net proceeds from an issuance of preferred equity and an
asset sale completed after September 30, 2005 will similarly be subject to such
use of proceeds provisions of the Company's indentures, and the Company
- 27 -
anticipates that, on the basis described above (after considering capital
expenditures), an additional $452.1 million will need to be used to acquire
other assets or capital stock, or to repurchase or repay indebtedness, as
applicable, within 365 days of the consummation of the applicable transaction.
As noted above, the Company sold its remaining oil and gas assets on July
7, 2005, with the gas component of such sale constituting "designated assets"
under certain of the Company's indentures. These indentures require the Company
to make an offer to purchase its First Priority Notes with the net proceeds of a
sale of designated assets not otherwise applied in accordance with the other
permitted uses under such indentures and, to the extent any proceeds (above $50
million) remain thereafter, to make an offer to purchase its second priority
senior secured debt. Accordingly, the Company made an offer to purchase the
First Priority Notes in June 2005. On July 12, 2005, the Company purchased, with
proceeds of the sale of the gas assets, $138.9 million in principal amount of
the First Priority Notes tendered in connection with the offer to purchase.
Having completed the tender offer, the Company has used approximately $308.2
million of the $708.5 million of the remaining net proceeds from the sale of its
gas assets to acquire natural gas and/or geothermal energy assets permitted to
be acquired under its Second Priority Secured Debt Instruments. There can be no
assurance that the Company will be successful in identifying or acquiring any
additional such assets on acceptable terms or at all. If the Company does not,
within 180 days of receipt of the net proceeds from the sale of its gas assets,
use all of the remaining net proceeds to acquire such assets, and/or to
repurchase or repay (through open market or privately negotiated transactions,
tender offers or otherwise) any or all of the $641.5 million aggregate principal
amount of First Priority Notes remaining outstanding after consummation of the
offer to purchase discussed above (either of which actions the Company may, but
is not required, to take), then the Company will, to the extent that the
remaining net proceeds from the sale, together with other applicable asset sales
and issuances of preferred equity, exceed $50.0 million, be required under the
terms of its Second Priority Secured Debt Instruments to make an offer to
purchase its outstanding second priority senior secured indebtedness, of which
$3.7 billion is outstanding, up to the amount of the remaining net proceeds. As
described further in Note 12, on September 26, 2005, the Company filed a lawsuit
seeking access to blocked proceeds remaining from this sale of designated
assets. If the Company does not ultimately prevail in this lawsuit, particularly
if the Company is compelled to return previously withdrawn amounts to the gas
sale proceeds account as more fully described in Note 12, it could have a
material adverse effect on the Company and its liquidity.
In connection with several of our subsidiaries' lease financing
transactions (Agnews, Geysers, Pasadena, Broad River, RockGen, and South Point)
the insurance policies we have in place do not comply in every respect with the
insurance requirements set forth in the financing documents. The Company has
requested from the relevant financing parties, and is expecting to receive,
waivers of this noncompliance. While failure to have the required insurance in
place is listed in the financing documents as an event of default, the financing
parties may not unreasonably withhold their approval of the Company's waiver
request so long as the required insurance coverage is not reasonably available
or commercially feasible, and a report is delivered from the Company's insurance
consultant to that effect. The Company has delivered the required insurance
consultant reports to the relevant financing parties and therefore anticipates
that the necessary waivers will be executed shortly.
In connection with the sale/leaseback transaction of Agnews, the Company
has not fully complied with covenants pertaining to the operations and
maintenance agreement, which noncompliance is technically an event of default.
The Company is in the process of addressing this by seeking the lessor's
approval to renew and extend the operations and maintenance agreement for the
Agnews facility.
In connection with the sale/leaseback transaction of Calpine Monterey
Cogeneration, Inc., the Company has not fully complied with covenants pertaining
to amendments to gas and power purchase agreements and the requirements to
provide a detailed accounting report, which noncompliance is technically an
event of default. The Company is in the process of addressing this by seeking a
consent and waiver.
2014 Convertible Notes -- The Company received a letter dated October 24,
2005, on behalf of Whitebox Convertible Arbitrage Fund, L.P. and Harbert
Convertible Arbitrage Master Fund, Ltd. (and certain affiliated funds of each)
that, collectively, claim to hold at least 25% of the 2014 Convertible Notes.
The letter purports to be a notice of default, which the Company would have 30
days to cure, under the indenture governing the 2014 Convertible Notes. The
basis of the claimed default is the Company's decision not to instruct the Bid
Solicitation Agent for the 2014 Convertible Notes to begin to determine the
"Trading Price" of the 2014 Convertible Notes after (i) the Company received a
July 5, 2005 letter from Harbert Convertible Arbitrage Master Fund, Ltd. and/or
its affiliates (the "Harbert Funds") and (ii) the Harbert Funds served an
affidavit on July 19, 2005 in the litigation described in Note 12, in each case
claiming that the Trading Price was below a threshold specified in the 2014
Convertible Notes. The Company maintains that the information provided by the
- 28 -
Harbert Funds in the July 5 letter did not constitute the "reasonable evidence"
required to be provided under the 2014 Convertible Notes indenture before the
Company would be required to instruct the Bid Solicitation Agent to begin to
determine the Trading Price. The Company also maintains that the July 19
affidavit was not a proper notice under the indenture, and in any event likewise
did not constitute "reasonable evidence" as required under the indenture.
Accordingly, the Company maintains that there is no default under the 2014
Convertible Notes indenture. The basis of the claimed default is currently the
subject of litigation as further described in Note 12.
Unrestricted Subsidiaries -- The information in this paragraph is required
to be provided under the terms of the Company's 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.
8. 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, 2005, due to reclassifications to discontinued operations to
reflect the sales or "held for sale" designations of the assets sold or to be
sold.
Oil and Gas Production and Marketing
On September 1, 2004, the Company, together with Calpine Natural Gas L.P.,
a Delaware limited partnership, completed the sale of its U.S. 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 represented approximately 120 Bcfe of proved gas reserves, producing
approximately 16.3 Mmcfe per day of gas. Under the terms of the agreement,
Calpine received net cash payments of approximately $218.7 million, and recorded
a pre-tax gain of approximately $103.7 million.
On September 2, 2004, the Company completed the sale of its Canadian
natural gas reserves and petroleum assets. These Canadian assets represented
approximately 221 Bcfe of proved reserves, producing approximately 61 Mmcfe per
day. Included in this sale was the Company's 25% interest in approximately 80
Bcfe of proved reserves (net of royalties) and 32 Mmcfe per day of production
owned by CNGT. In accordance with SFAS No. 144, the Company's 25% equity method
investment in 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$808.1 million, or approximately US$626.4 million. Calpine
initially recorded a pre-tax gain of approximately $104.5 million on the sale of
these Canadian assets net of $20.1 million in foreign exchange losses recorded
in connection with the settlement of forward contracts entered into to preserve
the US dollar value of the Canadian proceeds. Subsequent to the close of the
sale, the Company recognized an adjustment to the pre-tax gain related to
working capital; this adjustment reduced the pre-tax gain by $3.2 million,
resulting in a total pre-tax gain of $101.3 million.
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 U.S. 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.
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.
On July 7, 2005, the Company completed the sale of substantially all of its
remaining oil and gas assets to Rosetta for $1.05 billion, less approximately
$60 million of estimated transaction fees and expenses. The Company recorded a
pre-tax gain of approximately $340.2 million, which is reflected in discontinued
operations in the three and nine-months ended September 30, 2005. Approximately
- 29 -
$75 million of the purchase price was withheld pending the transfer of certain
properties for which consents had not yet been obtained at the closing date.
Subsequent to September 30, 2005, the Company had received a number of these
consents but none of the $75 million had been released to the Company due to the
refusal of the Collateral Trustee to release liens on the applicable properties.
The Company has brought a lawsuit against the Collateral Trustee as discussed
below and in Note 12. It is anticipated that consents will be obtained for the
remaining properties by December 31, 2005. These assets are reflected in the
September 30, 2005 and December 31, 2004 Consolidated Condensed Balance Sheets
as other current assets held for sale in the Summary section below. The portion
of any amount received in respect of these properties for natural gas assets
will constitute proceeds of a sale of "designated assets" and will be subject to
the requirements described in Note 7 under "Indenture and Debt and Lease
Covenant Compliance."
As discussed in Note 12, the Collateral Trustee for the Company's Senior
Secured Noteholders informed the Company of disagreements purportedly raised by
certain holders of its First Priority Notes regarding the Company's reinvestment
of the proceeds from this sale of domestic gas assets. As a result of these
concerns, the Collateral Trustee informed the Company that they will be
withholding further withdrawals from the gas sale proceeds account until these
disagreements can be resolved. In addition, the Collateral Trustee not released
liens on certain properties for which consents were received after the closing
of the sale and, accordingly, the Company has not received payment for such
properties. On September 26, 2005, the Company filed a lawsuit against the
Collateral Trustee and the Trustee for the First Priority Notes. See Notes 7 and
12 for further discussion regarding the use of the proceeds of the sale of the
gas assets and the status of the related legal matter.
In connection with the sale of the oil and gas assets to Rosetta, the
Company entered into a four and one-half year gas purchase agreement expiring on
December 31, 2009, for 100% of the production of the Sacramento Basin assets,
which represent approximately 44% of the reserve assets sold to Rosetta. The
Company will pay prevailing current market index prices for all amounts acquired
under the agreement. The Company believes the gas purchase agreement was
negotiated on an arm's length basis and represents fair value for the
production. Therefore, the agreement does not provide the Company with
significant influence over the buyer's ability to realize the economic risks and
rewards of owning the assets.
Electric Generation and Marketing
On January 15, 2004, the Company completed the sale of its 50% undivided
interest in the 545-MW Lost Pines 1 Power Project to GenTex Power Corporation,
an affiliate of the LCRA. Under the terms of the agreement, the Company received
a cash payment of $148.6 million and recorded a gain before taxes of $35.3
million. In addition, CES entered into a tolling agreement with LCRA providing
for the option to purchase 250 MW of electricity through December 31, 2004.
On July 28, 2005, the Company completed the sale of its 1,200-MW Saltend
Energy Centre for approximately $862.9 million, $14.5 million of which related
to the estimated working capital adjustments. The Company recorded a pre-tax
gain for the three and nine months ended September 30, 2005 of approximately
$23.7 million, which is reflected in discontinued operations, as a result of the
disposal of its UK operations. As described in Note 12, certain bondholders
filed a lawsuit concerning the remaining use of proceeds from the sale of
Saltend.
In the three months ended September 30, 2005, the Company committed to a
plan to divest its 561-MW Ontelaunee power plant in Pennsylvania. On October 6,
2005, the Company completed the sale for $225 million, less estimated
transaction fees and expenses and closing adjustments of approximately $13.0
million. While the transaction closed October 6, 2005, the Company had met the
criteria necessary to classify the assets and liabilities related to Ontelaunee
as held for sale under SFAS No. 144 at September 30, 2005. These assets and
liabilities are reflected in the September 30, 2005 and December 31, 2004
Consolidated Condensed Balance Sheets as current and long-term assets and
liabilities held for sale and identified by balance sheet caption in the
"Summary" section below. Also, in accordance with SFAS No. 144, the Company
recorded an impairment charge of $136.8 million for the difference between the
estimated sale price (less estimated selling costs) and the facility's book
value as of September 30, 2005. This charge is reflected in discontinued
operations in the Consolidated Condensed Statement of Operations for the three
and nine-month periods ended September 30, 2005. See Note 5 for a discussion of
the Company's impairment evaluation relating to the sale of Ontelaunee and Note
3 for a discussion of possible additional material impairment charges relating
to the sale of other assets. In connection with the sale of Ontelaunee and in
accordance with the instruments governing its indebtedness, on October 6, 2005,
CCFC I commenced offers to purchase its outstanding secured term loans and notes
in an amount up to the net proceeds received from the Ontelaunee sale. The offer
to purchase term loans expired on October 28, 2005, and the offer to purchase
notes expired on November 4, 2005, without any term loans or notes having been
tendered for purchase. Any remaining proceeds from this asset sale will be used
in accordance with the Company's existing bond indentures.
- 30 -
In connection with the sale of Ontelaunee, the Company entered into a
ten-year parts and supplies service agreement, referred to as an LTSA, under
which the Company will provide major maintenance services and parts supply for
the significant equipment of the facility, and a five-year O&M agreement under
which the Company will provide services related to the day-to-day operations and
maintenance of the facility. Pricing of the LTSA and O&M service contracts is
based on actual cost plus a margin and will result in estimated annual gross
cash outflows of approximately $3.3 million and $2.7 million, respectively. The
Company also entered into a six-month ESA under which CES will provide power
management services, fuel management services, risk management services, and
other services related to the Ontelaunee facility, with expected gross cash
inflows of approximately $0.4 million annually. The ESA can be renewed after six
months upon the mutual agreement of both Calpine and the new owner. Under the
terms of the ESA, CES functions in an agency role and has no delivery or price
risk and has no economic risk or reward of ownership in the operations of the
Ontelaunee facility. The gross cash flows associated with the LTSA, O&M and ESA
agreements are insignificant to the ongoing entity (Calpine)and the component
and are considered indirect cash flows under EITF No. 03-13. Also, the Company
has no significant continuing involvement in the financial and economic decision
making of the disposed component.
On August 2, 2005, the Company completed the sale of its interest in the
156-MW Morris power plant in Illinois for $84.5 million. The Company had
previously determined that the facility was impaired at June 30, 2005, upon the
Company's commitment to a plan of divesture of the facility, and recorded an
impairment charge to continuing operations of $106.2 million based on the
difference between the estimated sale price and the facility's book value.
During the three months ended September 30, 2005, this charge was reclassified
to discontinued operations once the sale had closed. The Company also recorded a
pre-tax loss on the sale of $0.4 million, which is reflected in discontinued
operations.Net proceeds from this asset sale will be used in accordance with the
Company's existing bond indentures.
In connection with the sale of Morris, the Company entered into an ESA and
a gas purchase contract under which CES will provide Morris with certain energy
scheduling services and gas brokerage services to facilitate gas purchases for
the new owner on a month-to-month basis until the new owner can establish the
necessary infrastructure to secure its own gas supply. It is anticipated that
these agreements will be assigned to the new CalBear entity by year end 2005.
Under the terms of the ESA, CES functions in an agency role and has no delivery
or price risk and has no economic risk or reward of ownership in the operations
of the Morris facility. Estimated gross cash inflows from the ESA are
approximately $30,000 per month. Under the terms of the gas purchase contract,
CES serves as a broker executing back-to-back purchase/sale transactions on
behalf of Morris. However, CES bears only credit risk in the transaction, the
nature of which is financial rather than operational and is sufficiently
different in nature than the previous activities with the component. Gross
estimated cash flows from the gas purchase contract is approximately $19 million
on an annualized basis. The cash flows associated with these agreements are
insignificant to the ongoing entity (Calpine) and are considered indirect. Also,
the Company has no significant continuing involvement in the operations of the
disposed component.
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.
- 31 -
The table below presents the assets and liabilities held for sale by
segment as of September 30, 2005 (in thousands).
September 30, 2005
----------------------------------------------------
Electric Oil and Gas
Generation Production
and Marketing and Marketing Total
------------- ------------- ----------
Assets
Cash and cash equivalents ......................................... $ 1 $ -- $ 1
Accounts receivable, net .......................................... -- -- --
Inventories ....................................................... 2,007 -- 2,007
Other current assets .............................................. -- 44,842 44,842
Prepaid expenses .................................................. 302 -- 302
-------- ---------- ----------
Total current assets held for sale .............................. 2,310 44,842 47,152
-------- ---------- ----------
Property, plant and equipment ..................................... 210,213 -- 210,213
Other assets ...................................................... -- -- --
-------- ---------- ----------
Total long-term assets held for sale ........................... $ 210,213 $ -- $210,213
========== ========== ==========
Liabilities
Accounts payable .................................................. $ 718 $ -- $ 718
Current derivative liabilities .................................... -- -- --
Other current liabilities ......................................... 5,905 -- 5,905
-------- ---------- ----------
Total current liabilities held for sale ......................... 6,623 -- 6,623
-------- ---------- ----------
Deferred income taxes, net of current portion ..................... -- -- --
Long-term derivative liabilities .................................. -- -- --
Other liabilities ................................................. -- -- --
---------- ---------- ----------
Total long-term liabilities held for sale ...................... $ -- $ -- $ --
========== ========== ==========
December 31, 2004
----------------------------------------------------
Electric Oil and Gas
Generation Production
and Marketing and Marketing Total
------------- ------------- ----------
Assets
Cash and cash equivalents ......................................... $ 65,405 $ -- $ 65,405
Accounts receivable, net .......................................... 54,095 -- 54,095
Inventories ....................................................... 7,756 -- 7,756
Prepaid expenses .................................................. 14,840 -- 14,840
---------- ---------- ----------
Total current assets held for sale .............................. 142,096 -- 142,096
---------- ---------- ----------
Property, plant and equipment ..................................... 1,632,131 606,520 2,238,651
Other assets ...................................................... 20,826 924 21,750
---------- ---------- ----------
Total long-term assets held for sale ........................... $1,652,957 $ 607,444 $2,260,401
========== ========== ==========
Liabilities
Accounts payable .................................................. $ 34,070 $ -- $ 34,070
Current derivative liabilities .................................... 8,935 -- 8,935
Other current liabilities ......................................... 42,186 1,267 43,453
---------- ---------- ----------
Total current liabilities held for sale ......................... 85,191 1,267 86,458
---------- ---------- ----------
Deferred income taxes, net of current portion ..................... 135,985 -- 135,985
Long-term derivative liabilities .................................. 10,368 -- 10,368
Other liabilities ................................................. 21,562 8,384 29,946
---------- ---------- ----------
Total long-term liabilities held for sale ...................... $ 167,915 $ 8,384 $ 176,299
========== ========== ==========
- 32 -
The tables below presents significant components of the Company's income
from discontinued operations for the three and nine months ended September 30,
2005 and 2004, respectively, (in thousands).
Three Months Ended September 30, 2005
----------------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------- -------------
Total revenue .................................................... $ 73,186 $ 3,261 $ -- $ 76,447
============= ============= ============= === =========
Gain on disposal before taxes .................................... $ 25,843 $ 339,591 $ -- $ 365,434
Operating income (loss) from discontinued operations
before taxes ................................................... (173,414) 4,240 -- (169,174)
------------ ------------- ------------- ------------
Income (loss) from discontinued operations before taxes .......... $ (147,571) $ 343,831 $ -- $ 196,260
Income tax provision (benefit) ................................... 39,896 130,618 -- 170,514
------------ ------------- ------------- ------------
Income from discontinued operations, net of tax .................. $ (187,467) $ 213,213 $ -- $ 25,746
============ ============= ============= ============
Three Months Ended September 30, 2004
----------------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------- -------------
Total revenue..................................................... $ 130,471 $ 22,573 $ -- $ 153,044
============ ============= ============= ============
Gain on disposal before taxes..................................... $ -- $ 203,533 $ -- $ 203,533
Operating income (loss) from discontinued operations
before taxes.................................................... (6,701) 17,698 -- 10,997
------------ ------------- ------------- ------------
Income (loss) from discontinued operations before taxes........... $ (6,701) $ 221,231 $ -- $ 214,530
Income tax provision (benefit).................................... (2,666) 104,948 -- 102,282
------------ ------------- ------------- ------------
Income from discontinued operations, net of tax................... $ (4,035) $ 116,283 $ -- $ 112,248
============ ============= ============= ============
Nine Months Ended September 30, 2005
----------------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------- -------------
Total revenue..................................................... $ 368,274 $ 25,101 $ -- $ 393,375
============ ============= ============= ============
Gain on disposal before taxes..................................... $ 23,260 $ 337,012 $ -- $ 360,272
Operating income (loss) from discontinued operations
before taxes...................................................... (318,701) 33,655 -- (285,046)
------------ ------------- ------------- ------------
Income (loss) from discontinued operations before taxes........... $ (295,441) $ 370,667 $ -- $ 75,226
Income tax provision (benefit).................................... (3,186) 140,815 -- 137,629
------------ ------------- ------------- ------------
Income from discontinued operations, net of tax................... $ (292,255) $ 229,852 $ -- $ (62,403)
============ ============= ============= ============
Nine Months Ended September 30, 2004
----------------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------- -------------
Total revenue..................................................... $ 387,289 $ 71,207 $ -- $ 458,496
============ ============= ============= ============
Gain on disposal before taxes..................................... $ 35,327 $ 207,120 $ -- $ 242,447
Operating income (loss) from discontinued operations before
taxes........................................................... 7,962 77,362 -- 85,324
------------ ------------- ------------- ------------
Income from discontinued operations before taxes.................. $ 43,289 $ 284,482 $ -- $ 327,771
Income tax provision (benefit).................................... 8,457 83,604 -- 92,061
------------ ------------- ------------- ------------
Income from discontinued operations, net of tax................... $ 34,832 $ 200,878 $ -- $ 235,710
============ ============= ============= ============
- 33 -
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.
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
Interest Expense Allocation 2005 2004 2005 2004
- --------------------------- ------------ ------------- ------------- -------------
Electric generation and marketing
Saltend Energy Centre.......................................... $ 6,225 $ 1,178 $ 45,080 $ 5,170
Morris and Ontelaunee Power Plants............................. 2,955 4,896 14,549 14,797
------------ ------------- ------------- ------------
Total....................................................... $ 9,180 $ 6,074 $ 59,629 $ 19,967
============ ============= ============= ============
Oil and gas production and marketing
Canadian and Rockies........................................... $ -- $ 5,158 $ -- $ 17,893
Remaining oil and gas assets................................... 357 3,138 10,295 7,864
------------ ------------- ------------- ------------
Total....................................................... $ 357 $ 8,296 $ 10,295 $ 25,757
============ ============= ============= ============
9. Derivative Instruments
Summary of Derivative Values
The table below reflects the amounts that are recorded as assets and
liabilities at September 30, 2005, for the Company's derivative instruments (in
thousands):
Commodity
Interest Rate Derivative Total
Derivative Instruments Derivative
Instruments Net Instruments
------------- ----------- -----------
Current derivative assets .................................. $ -- $ 703,665 $ 703,665
Long-term derivative assets ................................ 1,959 923,292 925,251
----------- ----------- -----------
Total assets ............................................. $ 1,959 $ 1,626,957 $ 1,628,916
=========== =========== ===========
Current derivative liabilities ............................. $ (15,135) $ (958,962) $ (974,097)
Long-term derivative liabilities ........................... (48,530) (1,166,933) (1,215,463)
----------- ----------- -----------
Total liabilities ........................................ $ (63,665) $(2,125,895) $(2,189,560)
=========== =========== ===========
Net derivative liabilities ............................... $ (61,706) $ (498,938) $ (560,644)
=========== =========== ===========
Of the Company's net derivative liabilities, $202.1 million and $34.6
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 the Company also
records the net derivative assets of PCF in its balance sheet.
On March 31, 2005, Deer Park, an indirect, wholly owned subsidiary of
Calpine, entered into agreements to sell power to and buy gas from MLCI. The
agreements cover 650 MW of Deer Park's capacity, and deliveries under the
agreements began on April 1, 2005, and continue through December 31, 2010. To
assure performance under the agreements, Deer Park granted MLCI a collateral
interest in the Deer Park Energy Center. The power and gas agreements contain
terms as follows:
Power Agreements
Under the terms of the power agreements, Deer Park will sell power to MLCI
at fixed and index prices with a discount to prevailing market prices at the
time the agreements were executed. In exchange for the discounted pricing, Deer
Park received an initial cash payment of $195.8 million, net of $17.3 million in
transaction costs during the first quarter if 2005, and subsequently received
additional cash payments of $76.4 million, net of $2.9 million in transaction
costs, as additional power transactions were executed with discounts to
- 34 -
prevailing market prices. The cash received by Deer Park is sufficiently small
compared to the amount that would be required to fully prepay for the power to
be delivered under the agreements that the agreements have been determined to be
derivatives in their entirety under SFAS No. 133. The value of the derivative
liability at September 30, 2005, was $297.4 million. As Deer Park makes power
deliveries under the agreements, the liability will be satisfied and,
accordingly, the derivative liability will be reduced, and Deer Park will record
corresponding gains in income, supplementing the revenues recognized based on
discounted pricing as deliveries take place. The upfront payments received by
Deer Park from the transaction are recorded as cash flows from financing
activity in accordance with guidance contained in SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" (SFAS No. 149).
SFAS No. 149 requires that companies present cash flows from derivatives that
contain an "other-than-insignificant" financing element as cash flows from
financing activities. Under SFAS No. 149, a contract that at its inception
includes off-market terms, or requires an up-front cash payment, or both is
deemed to contain an "other-than-insignificant" financing element.
Gas Agreements
Under the terms of the gas agreements, Deer Park will receive quantities of
gas such that, when combined with fuel supply provided by Deer Park's steam
host, Deer Park will have sufficient contractual fuel supply to meet the fuel
needs required to generate the power under the power agreements. Deer Park will
pay both fixed and variable prices under the gas agreements. To the extent that
Deer Park receives fixed prices for power, Deer Park will receive a
volumetrically proportionate quantity of gas supply at fixed prices thereby
fixing the spread between the revenue Deer Park receives under the fixed price
power sales and the cost it pays under the fixed price gas purchases. To the
extent that Deer Park receives index-based prices for its power sales, it will
pay index-based prices for a volumetrically proportionate amount of its gas
supply.
Relationship of Net Derivative Assets or Liabilities to AOCI
At any point in time, it is highly unlikely that total net derivative
assets or liabilities will equal AOCI, net of tax from derivatives, for three
primary reasons:
o 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.
o 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.
o 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 AOCI 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 liabilities to
its accumulated other comprehensive loss, net of tax from derivative instruments
at September 30, 2005 (in thousands):
Net derivative liabilities...................................................................................... $ (560,644)
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness............................. 226,718
Cash flow hedges terminated prior to maturity................................................................... (24,408)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges..................... 119,451
AOCI from unconsolidated investees.............................................................................. 19,806
---------------
Accumulated other comprehensive loss from derivative instruments, net of tax (1)................................ $ (219,077)
===============
- ------------
<FN>
(1) Amount represents one portion of the Company's total AOCI balance. See Note
10 for further information.
</FN>
- 35 -
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" -- 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 purchases of $335.8 million and $563.3
million against sales in the three months ended September 30, 2005, and
September 30, 2004, respectively. The Company netted the purchases of $912.1
million and $1,255.8 million against sales in the nine months ended September
30, 2005, and September 30, 2004, respectively.
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 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, 2005.
September 30, 2005
----------------------------------
Gross Net
--------------- ----------------
Current derivative assets....................................................................... $ 4,766,711 $ 703,665
Long-term derivative assets..................................................................... 2,097,589 923,292
--------------- ---------------
Total derivative assets....................................................................... $ 6,864,300 $ 1,626,957
=============== ===============
Current derivative liabilities.................................................................. $ (5,022,008) $ (958,962)
Long-term derivative liabilities................................................................ (2,341,230) (1,166,933)
--------------- ---------------
Total derivative liabilities.................................................................. $ (7,363,238) $ (2,125,895)
=============== ===============
Net commodity derivative liabilities.......................................................... $ (498,938) $ (498,938)
=============== ===============
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, 2005 and 2004, respectively (in thousands):
Three Months Ended September 30,
---------------------------------------------------------------------------------------
2005 2004
------------------------------------------ ------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ --------- --------------- ----------- ----------
Natural gas derivatives (1) ............... $ 9,651 $ 94,546 $ 104,197 $ 777 $ (8,508) $ (7,731)
Power derivatives (1) ..................... (1,643) (127,642) (129,285) 1,142 (17,173) (16,031)
Interest rate derivatives (2) ............. 524 -- 524 2,369 -- 2,369
Currency derivatives ...................... -- -- -- -- (12,897) (12,897)
--------- --------- --------- --------- --------- ---------
Total ................................... $ 8,532 $ (33,096) $ (24,564) $ 4,288 $ (38,578) $ (34,290)
========= ========= ========= ========= ========= =========
- 36 -
Nine Months Ended September 30,
---------------------------------------------------------------------------------------
2005 2004
------------------------------------------ ------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ --------- --------------- ----------- ----------
Natural gas derivatives (1) ............... $ 10,417 $ 58,123 $ 68,540 $ 6,540 $ (11,610) $ (5,070)
Power derivatives (1) ..................... (1,947) (123,413) (125,360) 1,268 (53,818) (52,550)
Interest rate derivatives (2) ............. (316) -- (316) 1,421 6,035 7,456
Currency derivatives ...................... -- -- -- -- (12,897) (12,897)
--------- --------- --------- --------- --------- ---------
Total ................................... $ 8,154 $ (65,290) $ (57,136) $ 9,229 $ (72,290) $ (63,061)
========= ========= ========= ========= ========= =========
- ------------
<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" in the Consolidated Statements of
Operations.
</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, 2005 and 2004,
respectively (in thousands):
Three Months Ended September 30,
----------------------------------
2005 2004
----------------- ----------------
Natural gas and crude oil derivatives........................................................... $ 27,589 $ (1,746)
Power derivatives............................................................................... (297,481) (26,975)
Interest rate derivatives....................................................................... (6,665) (1,320)
Foreign currency derivatives.................................................................... (498) (501)
--------------- ---------------
Total derivatives............................................................................. $ (277,055) $ (30,542)
=============== ===============
Nine Months Ended September 30,
----------------------------------
2005 2004
----------------- ----------------
Natural gas and crude oil derivatives........................................................... $ 44,906 $ 23,487
Power derivatives............................................................................... (336,922) (69,998)
Interest rate derivatives....................................................................... (20,570) (11,286)
Foreign currency derivatives.................................................................... (1,499) (1,513)
--------------- ---------------
Total derivatives............................................................................. $ (314,085) $ (59,310)
=============== ===============
These tables include pre-tax losses of $175.3 million and $10.4 million for
the three months ended September 30, 2005 and 2004, respectively, and $199.4
million and $1.4 million for the nine months ended September 30, 2005 and 2004,
respectively, which are included in discontinued operations for all periods
presented.
As of September 30, 2005, 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 11 years for commodity and interest rate derivative
instruments, respectively. The Company estimates that pre-tax losses of $242.7
million would be reclassified from OCI into earnings during the twelve months
ended September 30, 2006, 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 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 (in thousands):
- 37 -
2010 &
2005 2006 2007 2008 2009 After Total
---------- ---------- ---------- ---------- ---------- ---------- ----------
Gas OCI .......................... $ 124,750 $ 340,855 $ 16,035 $ 2,975 $ 2,036 $ 2,621 $ 489,272
Power OCI ........................ (227,309) (510,504) (33,390) (6,465) (5,210) (4,283) (787,161)
Interest rate OCI ................ (1,744) (5,860) (3,876) (3,169) (3,027) (18,775) (36,451)
Foreign currency OCI ............. (498) (1,993) (1,603) (94) -- -- (4,188)
--------- --------- --------- --------- --------- --------- ---------
Total pre-tax OCI .............. $(104,801) $(177,502) $ (22,834) $ (6,753) $ (6,201) $ (20,437) $(338,528)
========= ========= ========= ========= ========= ========= =========
10. Comprehensive Income (Loss)
Comprehensive income (loss) is the total of net income (loss) and all other
non-owner changes in equity. Comprehensive income (loss) includes the Company's
net income (loss), unrealized gains and losses from derivative instruments that
qualify as cash flow hedges, unrealized gains and losses from available-for-sale
securities which are marked to market, the Company's share of its equity method
investee's OCI, and the effects of foreign currency translation adjustments. The
Company reports AOCI in its Consolidated Balance Sheet. The tables below detail
the changes during the nine months ended September 30, 2005 and 2004 in the
Company's AOCI balance and the components of the Company's comprehensive income
(loss) (in thousands):
Comprehensive
Income (Loss)
for the Three
Months Ended
Total March 31, 2005,
Accumulated June 30, 2005,
Available- Foreign Other and
Cash Flow for-Sale Currency Comprehensive September 30,
Hedges Investments Translation Income (Loss) 2005
----------- ----------- ----------- ------------- ---------------
Accumulated other comprehensive income (loss)
at January 1, 2005 ..................................... $ (140,151) $ 582 $ 249,080 $ 109,511
Net loss for the three months ended March 31, 2005 ....... $ (168,731)
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
before reclassification adjustment during the
three months ended March 31, 2005 .................... (90,719)
Reclassification adjustment for gain included in
net loss for the three months ended
March 31, 2005 ....................................... (4,044)
Income tax benefit for the three months ended
March 31, 2005 ....................................... 29,998
-----------
(64,765) (64,765) (64,765)
Available-for-sale investments:
Pre-tax gain on available-for-sale investments
for the three months ended March 31, 2005 ............ 1,150
Income tax provision for the three months
ended March 31, 2005 ................................. (451)
-----------
699 699 699
Foreign currency translation loss for the three
months ended March 31, 2005 .......................... (12,830) (12,830) (12,830)
----------- ----------- -----------
Total comprehensive loss for the three months
ended March 31, 2005 ................................... $ (245,627)
===========
Accumulated other comprehensive income (loss)
at March 31, 2005 ...................................... $ (204,916) $ 1,281 $ 236,250 $ 32,615
=========== =========== =========== ===========
Net loss for the three months ended June 30, 2005 ........ $ (298,458)
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
before reclassification adjustment during the
three months ended June 30, 2005 ....................... (134,289)
Reclassification adjustment for loss included in
net loss for the three months ended
June 30, 2005 .......................................... 41,074
Income tax benefit for the three months ended
June 30, 2005 .......................................... 27,872
-----------
(65,343) (65,343) (65,343)
(table continues)
- 38 -
Available-for-sale investments:
Pre-tax gain on available-for-sale investments
for the three months ended June 30, 2005 ............... 2,415
Income tax provision for the three months
ended June 30, 2005 .................................... (947)
-----------
1,468 1,468
Foreign currency translation loss for the three
months ended June 30, 2005 ............................. (20,860) (20,860) (20,860)
----------- ----------- -----------
Total comprehensive loss for the three months
ended June 30, 2005 .................................... $ (383,193)
===========
Total comprehensive loss for the six months
ended June 30, 2005 .................................... $ (628,820)
===========
Accumulated other comprehensive income (loss)
at June 30, 2005 ....................................... $ (270,259) $ 2,749 $ 215,390 $ (52,120)
=========== =========== =========== ===========
Net loss for the three months ended
September 30, 2005 ..................................... $ (216,689)
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
before reclassification adjustment during the
three months ended September 30, 2005 ................ (209,814)
Reclassification adjustment for loss included in
net loss for the three months ended
September 30, 2005 ................................... 277,055
Income tax provision for the three months ended
September 30, 2005 ................................... (16,059)
-----------
51,182 51,182 51,182
Available-for-sale investments:
Pre-tax loss on available-for-sale investments for
the three months ended September 30, 2005 ............ (4,523)
Income tax benefit for the three months ended
September 30, 2005 ................................... 1,774
-----------
(2,749) (2,749) (2,749)
Foreign currency translation loss for the three
months ended September 30, 2005 ...................... (171,687) (171,687) (171,687)
----------- ----------- -----------
Total comprehensive loss for the three months
ended September 30, 2005 ............................... $ (339,943)
===========
Total comprehensive loss for the nine months
ended September 30, 2005 ............................... $ (968,763)
===========
Accumulated other comprehensive income (loss)
at September 30, 2005 .................................. $ (219,077) $ -- $ 43,703 $ (175,374)
=========== =========== =========== ===========
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)
(table continues)
- 39 -
Comprehensive
Income (Loss)
for the Three
Months Ended
Total March 31, 2005,
Accumulated June 30, 2005,
Available- Foreign Other and
Cash Flow for-Sale Currency Comprehensive September 30,
Hedges Investments Translation Income (Loss) 2005
----------- ----------- ----------- ------------- ---------------
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 ..................................... $ 141,125
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 loss 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 ............................... $ 135,526
===========
Total comprehensive income for the nine months
ended September 30, 2004 ............................... $ 1,097
===========
Accumulated other comprehensive income (loss)
at September 30, 2004 .................................. $ (179,790) $ 3,613 $ 192,633 $ 16,456
=========== =========== =========== ===========
11. Loss Per Share
Basic loss per common share was computed by dividing net loss by the
weighted average number of common shares outstanding for the respective periods.
The dilutive effect of the potential exercise of outstanding options to purchase
shares of common stock is calculated using the treasury stock method. The
dilutive effect of the assumed conversion of certain convertible securities into
the Company's common stock is based on the dilutive common share equivalents and
the after tax distribution expense avoided upon conversion. The reconciliation
of basic and diluted loss per common share is shown in the following table (in
thousands, except per share data).
- 40 -
Periods Ended September 30,
-----------------------------------------------------------------------------------
2005 2004
----------------------------------------- ---------------------------------------
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......................... $ (242,435) 478,461 $ (0.51) $ 28,877 444,380 $ 0.07
Discontinued operations, net of tax........... 25,746 -- 0.06 112,248 -- 0.25
------------ --------- ----------- ----------- -------- ----------
Net income (loss)......................... $ (216,689) 478,461 $ (0.45) $ 141,125 444,380 $ 0.32
============ ========= =========== =========== ======== ==========
Diluted earnings (loss) per common share:
Common shares issuable upon exercise of stock
options using treasury stock method.......... -- 2,542
Income (loss) before discontinued operations
and cumulative effect of a change in
accounting principle......................... $ (242,435) 478,461 $ (0.51) $ 28,877 446,922 $ 0.07
Discontinued operations, net of tax........... 25,746 -- 0.06 112,248 -- 0.25
------------ --------- ----------- ----------- -------- ----------
Net income (loss)......................... $ (216,689) 478,461 $ (0.45) $ 141,125 446,922 $ 0.32
============ ========= =========== =========== ======== ==========
Periods Ended September 30,
-----------------------------------------------------------------------------------
2005 2004
----------------------------------------- ---------------------------------------
Net Loss Shares EPS Net Loss Shares EPS
------------- --------- ------------- ------------- --------- -----------
NINE MONTHS:
Basic and diluted loss per common share:
Loss before discontinued operations........... $ (621,476) 458,483 $ (1.36) $ (194,475) 425,682 $ (0.45)
Discontinued operations, net of tax........... (62,403) -- (0.13) 235,710 -- 0.55
------------ --------- ----------- ----------- -------- ----------
Net income (loss)......................... $ (683,879) 458,483 $ (1.49) $ 41,235 425,682 $ 0.10
============ ========= =========== =========== ======== ==========
The Company incurred losses before discontinued operations for the quarters
ended September 30, 2005 and 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 as using the basic shares produced the more dilutive
effect on the loss per share. Potentially convertible securities, shares to be
purchased under the Company's ESPP and unexercised employee stock options to
purchase a weighted average of 7.7 million and 55.1 million shares of the
Company's common stock were not included in the computation of diluted shares
outstanding during the nine months ended September 30, 2005 and 2004,
respectively, because such inclusion would be antidilutive.
For the three and nine months ended September 30, 2005 and 2004,
approximately 0.1 million and 4.0 million, respectively, weighted common shares
of the Company's outstanding 2006 Convertible Notes, respectively, were excluded
from the diluted EPS calculations as the inclusion of such shares would have
been antidilutive.
In connection with the convertible debentures payable to Calpine Capital
Trust III, net of repurchases, for the three months ended September 30, 2005 and
2004, and the nine months ended September 30, 2005 and 2004, there were 0.0
million, 11.9 million, 6.1 million and 11.9 million weighted average common
shares potentially issuable, respectively, that were excluded from the diluted
EPS calculation as their inclusion would be antidilutive. The convertible
debentures were redeemed in full on July 13, 2005.
For the three and nine months ended September 30, 2005 and 2004, under the
net share settlement method and in accordance with the new guidance of EITF
04-08 there were no shares potentially issuable and thus potentially included in
the diluted EPS calculation under the Company's 2023 Convertible Notes, 2014
Convertible Notes and 2015 Convertible Notes issued in November 2003, September
2004 and June 2005, respectively, because the Company's closing stock price at
each period end was below the conversion price. However, in future reporting
periods where the Company's closing stock price is above the conversion price
for any of these convertible instruments and the Company has income before
discontinued operations and cumulative effect of a change in accounting
principle, the holders of each note will receive the conversion value of the
note payable in cash up to the principal amount of the note, and Calpine common
stock for the notes conversion value in excess of such princpal amount.The
- 41 -
maximum potential shares issuable under the conversion provisions of the notes
would be as presented below. The actual number of potential shares will depend
on the closing stock price at conversion.
o 2023 Convertible Notes -- If the Company's closing stock price is
above the instrument's conversion price of $6.50, a maximum of
approximately 97.5 million shares would be included (if dilutive) in
the diluted EPS calculation;
o 2014 Convertible Notes -- If the Company's closing stock price is
above the instrument's conversion price of $3.85, a maximum of
approximately 166.7 million shares would be included (if dilutive) in
the diluted EPS calculation;
o 2015 Convertible Notes -- If the Company's closing stock price is
above the instrument's conversion price of $4.00, a maximum of
approximately 163.0 million shares would be included (if dilutive) in
the diluted EPS calculation;
For the three and nine months ended September 30, 2005, 1.2 million
weighted average common shares of the Company's contingently issuable (unvested)
restricted stock was excluded from the calculation of diluted EPS because the
Company's closing stock price has not reached the price at which the shares
vest, and, as discussed above, inclusion would have been anti-dilutive.
In conjunction with the offering of the 2014 Convertible Notes in September
2004, the Company entered into a ten-year Share Lending Agreement with DB
London, under which the Company loaned DB London 89 million shares of newly
issued Calpine common stock in exchange for a loan fee of $.001 per share and
other consideration. The Company has excluded the 89 million shares of common
stock subject to the Share Lending Agreement from the EPS calculation.
See Note 2 for a discussion of the potential impact of SFAS No. 128-R on
the calculation of diluted EPS.
12. Commitments and Contingencies
LTSA Cancellations
On July 5, 2005, Calpine and Siemens-Westinghouse executed an agreement to
settle various matters related to certain warranty disputes and to terminate
certain LTSAs. The Company received approximately $25.5 million as a net
settlement payment related to these matters, a portion of which related to
events in existence prior to June 30, 2005. Consequently, $3.6 million and $7.2
million were recorded in the three months ended June 30, 2005, and September 30,
2005, respectively, as a reduction in plant operating expense relating to
warranty recoveries and contract settlements of prior period repair expenses.
The remaining settlement proceeds were applied as a reduction to capitalized
turbine costs in the three months ended September 30, 2005.
On July 7, 2005, the Company announced that it had entered into a 15-year
Master Products and Services Agreement with GE. A related agreement replaces the
nine remaining LTSAs covering the Company's GE 7FA turbine fleet. The Company
expects to benefit from improved power plant performance and operations and
maintenance flexibility to service its plants to further lower costs.
Historically, GE provided full-service turbine maintenance for a select number
of Calpine power plants. Under the new agreement, Calpine will supplement its
operations with a variety of GE services. As of September 30, 2005, the Company
operates 44 power plants that are powered by GE gas turbines, representing
approximately 10,000 MW of capacity. The Company recorded LTSA cancellation
expense of $33.3 million in the three months ended June 30, 2005, as the key
terms and provisions of the cancellation agreement were finalized prior to June
30, 2005.
Turbines
The table below sets forth future turbine payments for construction and
development projects, as well as for unassigned turbines. It includes previously
delivered turbines, payments and delivery by year for the last turbine to be
delivered as well as payment required for the potential cancellation costs of
the remaining 28 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 28 turbines.
Units to Be
Year Total Delivered
- -------------------------------------- ---------- -----------
(In thousands)
October through December 2005................ $ 11,220 1
2006......................................... 4,480 --
2007......................................... 2,332 --
2008......................................... 2,699 --
---------- ----
Total...................................... $ 20,731 1
========== ====
- 42 -
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 Financial Statements.
Securities Class Action Lawsuits. Beginning on March 11, 2002, fifteen
securities class action complaints were filed in the U.S. District Court for the
Northern District of California against Calpine and certain of its employees,
officers, and directors. All of these actions were ultimately assigned to Judge
Saundra Brown Armstrong, and Judge Armstrong ordered the actions consolidated
for all purposes on August 16, 2002, as In re Calpine Corp. Securities
Litigation, Master File No. C 02-1200 SBA. In mid-October, 2005, an agreement in
principle to settle this case was reached. The proposed settlement will resolve
the only claim remaining in these consolidated actions, which is a claim by two
plaintiffs for an alleged violation of Section 11 of the Securities Act of 1933.
All of the other claims brought in the consolidated actions were dismissed with
prejudice in February 2004. Judge Armstrong denied the motion for class
certification on August 10, 2005. The settlement amount is being paid by
insurance. The Company currently expects the settlement to be finalized before
the end of 2005.
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. This case is
a Section 11 case brought as a class action on behalf of purchasers in Calpine's
April 2002 stock offering. This case was filed in San Diego County Superior
Court on March 11, 2003. Defendants won a motion to transfer the case to Santa
Clara County. Defendants in this case are Calpine, Peter Cartwright, Ann B.
Curtis, John Wilson, Kenneth Derr, George Stathakis, Credit Suisse First Boston,
Banc of America Securities, Deutsche Bank Securities, and Goldman, Sachs & Co.
The Hawaii Fund alleges that the prospectus and registration statement for the
April 2002 offering had false or misleading statements regarding: Calpine's
actual financial results for 2000 and 2001; Calpine's projected financial
results for 2002; Mr. Cartwright's agreement not to sell or purchase shares
within 90 days of the offering; and Calpine's alleged involvement in "wash
trades." A central allegation of the complaint is that a March 2003 restatement
concerning the accounting for two sales-leaseback transactions revealed that
Calpine had misrepresented its financial results in the prospectus/registration
statement for the April 2002 offering.
There is no trial date in this action. The next scheduled court hearing
will be a case management conference on January 10, 2006, at which time the
court may set a trial date. We consider this lawsuit to be without merit and
intend to continue to defend vigorously against the allegations.
Phelps v. Calpine Corporation, et al. On April 17, 2003, James Phelps filed
a class action complaint in the Northern District of California, alleging claims
under the ERISA. On May 19, 2003, a nearly identical class action complaint was
filed in the Northern District by Lenette Poor-Herena. The parties agreed to
have both of the ERISA actions assigned to Judge Armstrong, who oversees the
above-described federal securities class action and the Gordon derivative action
(see below). On August 20, 2003, pursuant to an agreement between the parties,
Judge Armstrong ordered that the two ERISA actions be consolidated under the
caption, In re Calpine Corp. ERISA Litig., Master File No. C 03-1685 SBA (the
"ERISA Class Action"). Plaintiff James Phelps filed a consolidated ERISA
complaint on January 20, 2004 ("Consolidated Complaint"). Ms. Poor-Herena is not
identified as a plaintiff in the Consolidated Complaint.
The Consolidated Complaint defines the class as all participants in, and
beneficiaries of, the Plan for whose accounts investments were made in Calpine
stock during the period from January 5, 2001 to the present. The Consolidated
Complaint names as defendants Calpine, the members of its Board of Directors,
the Plan's Advisory Committee and its members (Kati Miller, Lisa Bodensteiner,
Rick Barraza, Tom Glymph, Patrick Price, Trevor Thor, Bob McCaffrey, and Bryan
Bertacchi), signatories of the Plan's Annual Return/Report of Employee Benefit
Plan Forms 5500 for 2001 and 2002 (Pamela J. Norley and Marybeth Kramer-Johnson,
respectively), an employee of a consulting firm hired by the Plan (Scott
Farris), and unidentified fiduciary defendants. The Consolidated Complaint
alleges that defendants breached their fiduciary duties involving the Plan, in
violation of ERISA, by misrepresenting Calpine's actual financial results and
earnings projections, failing to disclose certain transactions between Calpine
and Enron that allegedly inflated Calpine's revenues, failing to disclose that
the shortage of power in California during 2000-2001 was due to withholding of
capacity by certain power companies, failing to investigate whether Calpine
common stock was an appropriate investment for the Plan, and failing to take
appropriate actions to prevent losses to the Plan. In addition, the Consolidated
Complaint alleges that certain of the individual defendants suffered from
conflicts of interest due to their sales of Calpine stock during the class
period.
- 43 -
Defendants moved to dismiss the Consolidated Complaint. Judge Armstrong
granted the motion and dismissed three of the four claims with prejudice. The
remaining claim, for misrepresentation, was dismissed with leave to amend.
Plaintiff filed an Amended Consolidated Complaint on June 3, 2005. The Amended
Consolidated Complaint names as defendants Calpine Corporation and the members
of the Advisory Committee for the Plan. Defendants have filed motions to dismiss
the Amended Consolidated Complaint, which are currently scheduled for hearing on
December 6, 2005. We consider this lawsuit to be without merit and intend to
continue to defend vigorously against the allegations.
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 styled Johnson vs. Cartwright, et al. (No.
CV803872) and is pending in California Superior Court in 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, naming
additional officer defendants. Calpine and the individual defendants filed
demurrers (motions to dismiss) and a motion to stay the case in March 2003. On
July 1, 2003, the Court granted Calpine's motion to stay this proceeding until
In re Calpine Corporation Securities Litigation is resolved, or until further
order of the Court. The Court did not rule on the demurrers. We consider this
lawsuit to be without merit and intend to defend vigorously against the
allegations if the stay is lifted.
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 were 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
until In re Calpine Corporation Securities Litigation is resolved, and to
dismiss without prejudice certain director defendants. The Court did not rule on
the motions to dismiss the complaint on non-jurisdictional grounds. On March 4,
2003, plaintiff filed papers with the court voluntarily agreeing to dismiss
without prejudice his claims against three of the outside directors. We consider
this lawsuit to be without merit and intend to defend vigorously against the
allegations if the stay is lifted.
International Paper Company v. Androscoggin Energy LLC. In October 2000,
International Paper Company filed a complaint 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 price of gas under its gas supply
agreements. We had acquired a 32.3% economic interest and a 49.5% voting
interest in AELLC as part of the Skygen transaction, which closed in October
2000. 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 International Paper Company on the liability aspect
of a particular claim against AELLC. On December 11, 2003, the court denied in
part IP's summary judgment motion pertaining to damages and determined that, (i)
IP was entitled to pursue an action for damages, and (ii) ruled that sufficient
questions of fact remain to deny IP summary judgment on the measure of damages.
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. AELLC has made an additional accrual to recognize
the jury verdict, and the Company has recognized its 32.3% share. AELLC filed a
post-trial motion challenging both the determination of its liability and the
damages award and, on November 16, 2004, the court entered an order staying the
execution of the judgment. The order staying execution of the judgment has not
expired. On September 30, 2005, the district court denied AELLC's Motion for
Judgment as a Matter of Law, or, in the Alternative, Remittitur or a New Trial.
AELLC intends to appeal the judgment.
Additionally, on November 26, 2004, AELLC filed a voluntary petition for
relief under Chapter 11 of the Bankruptcy Code. AELLC is continuing in
possession of its property and is operating and maintaining its business as a
debtor in possession, pursuant to Section 1107(a) and 1108 of the Bankruptcy
Code. AELLC filed its, (i) Plan of Reorganization, and (ii) Disclosure Statement
regarding such plan, on September 30, 2005.
Finally, AELLC filed a Demand for Arbitration on July 8, 2005, seeking
damages from IP regarding three separate ESA billing disputes. IP filed its
Answering Statement and Counterclaim on July 29, 2005. The parties are in the
preliminary stages of the AAA arbitration procedures.
- 44 -
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 the Company and
certain of its affiliates 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 power plant, 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 of the Oneta plant and that the
Company's actions have reduced the profits from Oneta thereby undermining
Panda's ability to repay monies owed to the Company on December 1, 2003, under a
promissory note on which approximately $38.6 million (including interest) is
currently outstanding. The Company has filed a counterclaim against Panda Energy
International, Inc. (and PLC II, LLC) based on a guaranty, and has also filed a
motion to dismiss as to the causes of action alleging federal and state
securities laws violations. The court recently granted the Company's motion to
dismiss the above claims, but allowed Panda an opportunity to replead. We
consider Panda's lawsuit to be without merit and intend to vigorously defend it.
Discovery is currently in progress. The Company stopped accruing interest income
on the promissory note due December 1, 2003, as of the due date because of
Panda's default on repayment of the note. Trial is currently set for May 22,
2006.
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 was also named in eight other
similar complaints for violations of Section 17200. The Company considered the
allegations to be without merit, and filed a motion to dismiss. The court
granted the motion, and plaintiffs appealed. The Ninth Circuit has issued a
decision affirming the dismissal of the Pastorino group of cases. The
Plaintiff's did not attempt to appeal the Ninth Circuit's ruling to the Supreme
Court so the matter is resolved.
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. Millar was removed to federal
court, but has now been remanded back to state superior court for handling.
Hearings on multiple demurrers were held on September 7, 2005 at which time, the
Judge dismissed the case without leave to amend. Millar did not attempt to
appeal the dismissal ruling. Thus, the entire case is now resolved.
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, NPC and 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,
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 spot
power market was dysfunctional and that they are unjust and unreasonable. The
complaint therefore sought modification of the contract prices. 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 and SPPC
the relief that they were seeking. In a June 26, 2003 order, FERC affirmed the
judge's findings and dismissed the complaint, and subsequently denied rehearing
of that order. The matter is pending on appeal before the United States Court of
Appeals for the Ninth Circuit. The Company has participated in briefing and
arguments before the Ninth Circuit defending the FERC orders, but the Company is
not able to predict at this time the outcome of the Ninth Circuit appeal.
Transmission Service Agreement with Nevada Power Company. On September 30,
2004, Nevada Power Company ("NPC") filed a complaint in state district court of
Clark County, Nevada against Calpine Corporation ("Calpine"), Moapa Energy
Center, LLC, Fireman's Fund Insurance Company ("FFIC") and unnamed parties
alleging, among other things, breach by Calpine of its obligations under a
Transmission Service Agreement ("TSA") between Calpine and NPC for 400 megawatts
of transmission capacity and breach by FFIC of its obligations under a surety
bond, which surety bond was issued by FFIC to NPC to support Calpine's
obligations under the TSA. This proceeding was removed from state court to
United States District Court for the District of Nevada. On December 10, 2004,
FFIC filed a Motion to Dismiss, which was granted on May 25, 2005 with respect
to claims asserted by NPC that FFIC had breached its obligations under the
surety bond by not honoring NPC's demand that the full amount of the surety bond
($33,333,333.00) be paid to NPC in light of Calpine's failure to provide
replacement collateral upon the expiration of the surety bond on May 1, 2004.
NPC has filed a Motion to Amend the Complaint and a Motion for Reconsideration
of the above dismissal. The above dismissal is specific to NPC's claims against
FFIC and does not address NPC's specific claims against Calpine or Moapa Energy
Center, LLC. Discovery is proceeding. At this time, Calpine is unable to predict
the outcome of this proceeding.
- 45 -
Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6,
2002, Calpine Canada filed a complaint in the Alberta Court of Queens Branch
alleging that 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. We have finished discovery and are currently in
settlement discussions. The Company believes that Enron Canada's counterclaim is
without merit and intends to vigorously defend against it.
Estate of Jones, et al. 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 Mr. Darrell Jones of 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. The complaint alleged 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. 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 the estates
(which has been remitted) to ensure payment of these fees. The matter is
currently on appeal, both parties have filed briefs with the appellate court,
and oral arguments were heard by the court on October 17, 2005. We are waiting
for the court to issue its decision.
Calpine Energy Services v. Acadia Power Partners. Calpine Corporation,
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 Corporation subsidiary owns the other 50% of the Facility. Calpine Energy
Services, LP ("CES") is the purchaser under two power purchase agreements with
APP pursuant to which CES has the right to purchase all of the output from the
Facility. During the summer of 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 had asserted that it is entitled to certain
relief from the purchase agreements, and that APP had to cure certain defaults
under the purchase agreements, to which assertions APP disagrees. After engaging
in the initial alternative dispute resolution steps set forth in the power
purchase agreements the parties settled their disputes.
In addition, CES and APP had been discussing certain billing calculation
disputes that relate to efficiency matters. The dispute covers the time period
from June 2002 (COD of the plant) to June 2004. The parties have completely
resolved this matter.
Hulsey, et al. v. Calpine Corporation. On September 20, 2004, Virgil D.
Hulsey, Jr. (a current employee) and Ray Wesley (a former employee) filed a
class action wage and hour lawsuit against Calpine Corporation and certain of
its affiliates. The complaint alleges that the purported class members were
entitled to overtime pay and Calpine failed to pay the purported class members
at legally required overtime rates. The matter has been transferred to the Santa
Clara County Superior Court and Calpine filed an answer on January 7, 2005,
denying plaintiffs' claims. This case has tentatively been settled.
Michael Portis v. Calpine Corp. - Complaint Filed with Department of Labor.
On January 25, 2005, Michael Portis ("Portis"), a former employee of Calpine,
brought a complaint to the United States Department of Labor (the "DOL"),
alleging that his employment with the Company was wrongfully terminated. Portis
alleged that Calpine and its subsidiaries evaded sales and use tax in various
states and in doing so filed false tax reports and that his employment was
terminated in retaliation for having reported these allegations to management.
Portis claimed that the Company's alleged actions constitute violations of the
employee protection provisions of the Sarbanes Oxley Act of 2002. On April 27,
2005, the DOL determined that Portis' retaliatory discharge complaint had no
merit and dismissed it. On June 13, 2005, Portis filed an objection and
requested a hearing before an Administrative Law Judge. After an initial hearing
with the ALJ, and a failed attempt to elicit a settlement, Portis withdrew the
objection and hearing request. On August 12, 2005, the DOL's initial finding
(that the complaint had no merit) was reinstated and made final.
Auburndale Power Partners and Cutrale. Calpine Corporation owns an interest
in the Auburndale PP cogeneration facility, which provides steam to Cutrale, a
juice company. The Auburndale PP facility currently operates on a "cycling"
basis whereby the plant operates only a portion of the day. During the hours
that the Auburndale PP facility is not operating, Auburndale PP does not provide
steam to Cutrale. Cutrale has filed an arbitration claim alleging that they are
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entitled to damages due to Auburndale PP's failure to provide them with steam 24
hours a day. Auburndale PP disagreed with Cutrale's position based on its
interpretation of the contractual language in the Steam Supply Agreement.
Binding arbitration was conducted on the contractual interpretation issue only
(reserving the remedy/damage issue for a second phase to the arbitration) and
the arbitrator found in favor of Cutrale's contractual interpretation. The
proceeding now turns to the second phase, the resolution of the issue regarding
the appropriate remedy/damage determination. To preserve our positive
relationship with Cutrale, Auburndale PP continues to try to resolve the matter
through a commercial settlement.
Harbert Distressed Investment Master Fund, Ltd. v. Calpine Canada Energy
Finance II ULC, et al. On May 5, 2005, Harbert Distressed Investment Master
Fund, Ltd. (the "Harbert Fund") filed an Originating Notice (Application) (the
"Original Application") in the Supreme Court of Nova Scotia against Calpine
Corporation and certain of its subsidiaries, including Calpine Canada Energy
Finance II ULC ("Finance II"), the issuer of certain bonds (the "Bonds") held by
the Harbert Fund and CCRC, the parent company of Finance II and the indirect
parent company of Saltend. The Bonds have been guaranteed by Calpine. The
Harbert Fund alleged that Calpine, CCRC and Finance II violated the Harbert
Fund's rights under Nova Scotia laws in connection with certain financing
transactions completed by CCRC or subsidiaries of CCRC. Wilmington Trust
Company, the trustee under the indenture governing the Bonds (the "Trustee"),
was a co-applicant in the suit on behalf of all holders of Bonds. The hearing
was conducted on July 6, 7 and 8, 2005 before the Nova Scotia Supreme Court. The
claims as against Calpine European Funding (Jersey) Limited and Calpine (Jersey)
Limited, were discontinued by Consent Order dated July 20, 2005,
On August 2, 2005, the Court dismissed the Harbert Fund's application for
relief and denied all relief to the Harbert Fund and all other bondholders that
purchased Bonds on or after September 1, 2004. However, the Court stated that a
remedy should be granted to any bondholder, other than the Calpine respondent
companies, that purchased Bonds prior to September 1, 2004 and that continues to
hold those Bonds on August 2, 2005 (the "Eligible Bondholders").
The Court directed the Trustee to provide the face amount of qualifying
Bonds and the identity of the holders of such Bonds by August 31, 2005
(subsequently modified by the Bond Indemnification Order described below). Upon
receipt of such information, the Court will then issue a final order requiring
Calpine to maintain in the control of CCRC sufficient proceeds from the sale of
Saltend to cover the face amount of such Bonds. If there are insufficient
proceeds for this purpose, Calpine will be required to place in the control of
CCRC an additional amount which, when added to the net Saltend sale proceeds,
will cover the face value of all such Bonds. On September 20, 2005, the Court
issued a Bond Identification Order confirming a process for determining the list
of Eligible Bondholders and further required the Indenture Trustee to file a
report of such determination on or before November 18, 2005. The final order
will further provide that CCRC shall diligently conduct its business in a proper
and efficient manner so as to preserve and protect its business and assets.
Pending the final order, the Court issued an interim order under which Calpine
must maintain the net Saltend sale proceeds in the control of CCRC.
Any party to the proceeding has the right to appeal the final order to the
Nova Scotia Court of Appeal.
On October 6, 2005, the Trustee and the Harbert Fund issued a demand letter
to Finance II and its directors demanding that Finance II commence proceedings
against CCRC to enforce various rights under a Term Debenture due 2021 issued by
CCRC to Finance II. On October 7, 2005, the Trustee and the Harbert Fund filed
an Originating Notice (Application) in the Supreme Court of Nova Scotia against
CCRC and sought leave to commence a derivative proceeding on behalf of Finance
II (the "Harbert/WTC Leave Application") seeking to enforce such rights under
the Term Debenture. On October 11, 2005, Finance II and CCRC filed an
Interlocutory Notice Application seeking either a dismissal of the Harbert/WTC
Leave Application or, alternatively, a stay of such pending the completion of
the process set out in the Bond Identification Order, issuance of a final order
in the Original Application and disposition of any appeals in the Original
Application ("Calpine Cross-Application") on the bases of res judicata and abuse
of process, arguing that the claims and relief sought by the applicants in the
Harbert/WTC Leave Application are the same, or arise out of the same facts and
circumstances, as the claims and relief that those applicants sought, and were
denied, in the Original Application. The Calpine Cross-Application is scheduled
to be heard as a preliminary application on November 22 and 23, 2005. The final
order in the Original Application, as well as the Harbert/WTC Leave Application
(if necessary), are scheduled to be heard on December 19 and 20, 2005.
Harbert Convertible Arbitrage Master Fund, Ltd. et al. v. Calpine
Corporation. Plaintiff Harbert Convertible Arbitrage Master Fund, Ltd. and two
affiliated funds filed this action on July 11, 2005, in Supreme Court, New York
County, State of New York, and filed an amended complaint on July 19, 2005. In
their amended complaint, plaintiffs allege that in a July 5, 2005 letter to
Calpine they provided "reasonable evidence" as required under the indenture
governing the 2014 Convertible Notes that, on one or more days beginning on July
1, 2005, the Trading Price of the 2014 Convertible Notes was less than 95% of
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the product of the Common Stock Price multiplied by the Conversion Rate, as
those terms are defined in the indenture, and that Calpine therefore was
required to instruct the Bid Solicitation Agent for the 2014 Convertible Notes
to determine the Trading Price beginning on the next Trading Day. If the Trading
Price as determined by the Bid Solicitation Agent were below 95% of the product
of the Common Stock Price multiplied by the Conversion Rate for the next five
consecutive Trading Days, then the 2014 Convertible Notes would become
convertible into cash and common stock for a limited period of time. Plaintiffs
have asserted a claim for breach of contract, seeking unspecified damages, based
on Calpine's not instructing the Bid Solicitation Agent to begin to calculate
the Trading Price. In addition, plaintiffs have sought a declaration that
Calpine had a duty, based on the statements in the July 5 letter, to commence
the bid solicitation process, and also have sought injunctive relief to force
Calpine to instruct the Bid Solicitation Agent to determine the Trading Price of
the Notes. Plaintiffs made, but later withdrew, a request for a preliminary
injunction. Calpine's motion to dismiss was served on September 6, 2005,
opposition and reply papers were subsequently served, and the Court has
scheduled argument on the motion for November 9, 2005. Harbert has informed
Calpine and the court that Wilmington Trust Company, as trustee under the
indenture for the 2014 Convertible Notes, intends to seek to intervene in the
case and/or to file a similar action for the benefit of all holders of the 2014
Convertible Notes.
Whitebox Convertible Arbitrage Fund, L.P., et al. v. Calpine Corporation.
Plaintiff Whitebox Convertible Arbitrage Fund, L.P. and seven affiliated funds
filed an action in the Supreme Court, New York County, State of New York, for
breach of contract on October 17, 2004. The factual allegations and legal basis
for the claims set forth in that action are nearly identical to those set forth
in the Harbert Convertible filings detailed above. On October 19, 2005,
plaintiffs filed a motion for preliminary injunctive relief, but withdrew the
motion on November 7, 2005. Whitebox has informed Calpine and the court that
Wilmington Trust Company, as trustee under the indenture for the 2014
Convertible Notes, intends to seek to intervene in the case and/or to file a
similar action for the benefit of all holders of the 2014 Convertible Notes.
SEC Informal Inquiry and Request for Documents and Information. On June 9,
2005, the Company filed a Current Report on Form 8-K with the SEC to disclose
that, in April 2005, the Division of Enforcement of the SEC informed the Company
that it was conducting an informal inquiry and asked the Company to voluntarily
provide documents and information related to: (a) the Company's downward
revision of its proved oil and gas reserve estimates at year-end 2004 as
compared to such estimates at year-end 2003, and a corresponding impairment of
the value of certain assets, all previously disclosed by the Company, (b)
certain statements made to various regulatory agencies by Michael Portis, a
terminated former employee, regarding the Company's determination of state sales
and use taxes, and (c) the Company's upward restatement in April 2005 of its
previously disclosed net income for the third quarter, and the first three
quarters, of 2004. The Company fully cooperated with the SEC's request for
documents and information.
Calpine Corporation v. The Bank of New York, Collateral Trustee for Senior
Secured Note Holders, et al. In September of 2005, Calpine received a letter
from The Bank of New York, the Collateral Trustee (the "Collateral Trustee") for
Calpine's senior secured debt holders, informing Calpine of disagreements
purportedly raised by certain holders of First Priority Notes regarding the
Company's reinvestment of the proceeds from its recent sale of natural gas
assets to Rosetta. As a result of these concerns, the Collateral Trustee
informed the Company that it would not allow further withdrawals from the gas
sale proceeds account until these disagreements are resolved. On September 26,
2005, Calpine filed a Declaratory Relief Action in the Delaware Court of
Chancery against the Collateral Trustee and Wilmington Trust Company, as trustee
for the First Priority Notes (the "First Priority Trustee"), seeking a
declaration that Calpine's past and proposed purchases of natural gas assets are
permitted by the indenture for the First Priority Notes and related documents,
and also seeking an injunction compelling the Collateral Trustee to release
funds requested to be withdrawn. The First Priority Trustee has counterclaimed,
seeking an order compelling the Company to, among other things, (i) pay damages
in an amount not less than $365 million plus prejudgment interest either to the
First Priority Trustee or into the gas sale proceeds account; (ii) return to the
gas sale proceeds account all amounts previously withdrawn from such account and
used by the Company to purchase natural gas in storage; and (iii) indemnify the
First Priority Trustee for all expenses incurred in connection with defending
the lawsuit and pursuing counterclaims. The Company has filed a motion to
dismiss the counterclaims on the grounds that the holders of the First Priority
Notes (and the First Priority Trustee on behalf of the holders of the First
Priority Notes) have no right under the indenture governing the First Priority
Notes to compel the return of such amounts or otherwise to object to the use of
the proceeds of the gas sale because the Company made an offer to purchase all
of the First Priority Notes with the proceeds of the gas sale and the holders of
the First Priority Notes declined such offer. In addition, Wilmington Trust
Company, as trustee for the Second Priority Notes (the "Second Priority
Trustee"), has intervened in the lawsuit. The Second Priority Trustee has
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counterclaimed seeking to compel the Company to return to the gas sale proceeds
account all amounts previously withdrawn therefrom and used by the Company to
purchase gas in storage. In its trial brief, the Company plans to request that
these counterclaims be dismissed on the bases that they were filed after the
deadline and without the Court's permission.
Discovery in this lawsuit commenced on a fast track and is near completion.
Pre-trial submissions were filed with the Court on November 7, 2005 and a bench
trial is scheduled to begin on November 11, 2005. The Company expects that the
trial will be completed in one day and that the Court will issue an opinion
shortly thereafter. The Company maintains that its use of the proceeds of the
natural gas sale to purchase natural gas in storage was appropriate and
permitted under the instruments governing its senior secured debt, including the
indenture governing the First Priority Notes and the Senior Secured Debt
Instruments, however, no assurance can be given that the Company will prevail in
this litigation.
Scott, et al. v. Calpine Corporation. On September 13, 2005, Calpine
received a letter from an attorney representing one current and six former
employees located in the Houston, Texas office. The letter alleges claims of
racial discrimination, retaliation, slander, a hostile work environment and
constructive discharge. The seven individuals have also filed Notices of Charge
of Discrimination with the U.S. Equal Employment Opportunity Commission. Outside
counsel has been retained and has investigated the claims in anticipation of
threatened litigation. We consider these claims to be without merit and intend
to defend vigorously against the allegations.
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 business strategy, it was the Company's objective to produce a
portion of its fuel consumption requirements from its own natural gas reserves
("equity gas"). However, with the July 2005 sale of the Company's remaining oil
and gas production and marketing activity, the Company now has one reportable
segment, Electric Generation and Marketing. No other components of the business
had reached the quantitative criteria to be considered a reportable segment
under SFAS No. 131. See Note 8 for a discussion of the sale of the Company's oil
and gas assets. Consequently, the revenue and expense from the Oil and Gas
Production and Marketing reportable segment has been reclassified to
discontinued operations and the remaining pipeline assets have been reflected in
the table below within Corporate, Eliminations, and Other.
Electric Generation and Marketing includes the development, acquisition,
ownership and operation of power production facilities, hedging, balancing,
optimization, and trading activity transacted on behalf of the Company's power
generation facilities. Corporate and other activities necessary to support the
Electric Generation and Marketing reporting segment consists primarily of
financing transactions, activities of the Company's parts and services
businesses, and general and administrative costs.
Electric Generation Corporate, Eliminations,
and Marketing and Other Total
------------------------ ------------------------ -----------------------
2005 2004 2005 2004 2005 2004
------------ ----------- ----------- ------------ ----------- -----------
(In thousands)
For the three months ended September 30,
Total revenue from external customers.................. $3,255,141 $2,396,483 $ 26,449 $ 15,250 $3,281,590 $2,411,733
Segment profit/(loss) before provision for
income taxes.......................................... (154,256) (15,426) (70,692) 23,979 (224,948) 8,553
Electric Generation Corporate, Eliminations,
and Marketing and Other Total
------------------------ ------------------------ -----------------------
2005 2004 2005 2004 2005 2004
------------ ----------- ----------- ------------ ----------- -----------
(In thousands)
For the nine months ended September 30,
Total revenue from external customers.................. $7,451,404 $6,414,619 $ 74,824 $ 51,713 $7,526,228 $6,466,332
Segment profit/(loss) before provision
for income taxes...................................... (758,894) (244,918) (30,448) 93,889) (789,342) (338,807)
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Electric
Generation Corporate, Eliminations,
and Marketing and Other Total
-------------- ------------------------ ----------------
(In thousands)
Total assets:
September 30, 2005.................................................. $ 25,381,709 $ 1,706,528 $ 27,088,237
December 31, 2004................................................... $ 25,187,414 $ 2,028,674 $ 27,216,088
14. California Power Market
California Refund Proceeding/June 19 FERC Order. On August 2, 2000, the
California Refund Proceeding was initiated by a complaint made at FERC by San
Diego Gas & Electric Company and 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 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 could total approximately $10.1 million (plus interest, if
applicable), after taking the appropriate set-offs for outstanding receivables
owed by CalPX and CAISO to Calpine. The Company has fully reserved the amount
referenced above. The final determination of the refund liability is subject to
further Commission proceedings to ascertain the allocation of payment
obligations among the numerous buyers and sellers in the California markets.
Furthermore, it is possible that there will be further proceedings to require
refunds from certain sellers for periods prior to the originally designated
Refund Period. In addition, the FERC orders concerning the Refund Period, the
method for calculating refund liability and numerous other issues are pending on
appeal before the U.S. Court of Appeals for the Ninth Circuit. At this time, the
Company is unable to predict the timing of the completion of these proceedings
or the final refund liability. The final outcome of this proceeding and 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, 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 Governor of the State of California, acting on behalf of
the executive branch of the State of California, the California Electricity
Oversight Board, the California Public Utilities Commission (California
Commission), and the People of the State of California by and through the
Attorney General (the "AG") (collectively, the "California State Releasing
Parties") on April 22, 2002. Calpine's settlement resulted in an 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 of the other California State Releasing Parties. On June 30, 2004, a
settlement conference was convened at the FERC to explore settlements among
additional parties. On December 7, 2004, FERC approved the settlement of the
California Refund Proceeding and other proceedings among Duke Energy Corporation
and its affiliates, the three California investor-owned utilities, and the
California governmental entities.
On September 9, 2004, the Ninth Circuit Court of Appeals issued a decision
on appeal (State of California, Ex. Rel. Bill Lockyer, Attorney General v.
Federal Energy Regulatory Commission) of a Petition for Review of an order
issued by FERC in FERC Docket No. EL02-71 wherein the AG had filed a complaint
(the "AG Complaint") under Sections 205 and 206 of the Federal Power Act (the
"FPA") 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 FPA from
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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 AG), Calpine and its
affiliates settled all claims related to the AG Complaint.
FERC Investigation into the 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, through their affiliates, 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 the Company 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
potentially be in violation of the CAISO or CalPX tariffs. The Company 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. The Final
Report also recommended that FERC modify the basis for determining potential
liability in the California Refund Proceeding discussed above. On June 25, 2003,
FERC issued a number of orders associated with these investigations. In
particular, based on the FERC staff's earlier recommendations in the Final
Report, FERC issued two show cause orders each naming certain industry
participants. The show cause orders have initiated proceedings wherein the named
parties must demonstrate that certain market behavior did not violate either the
CAISO or CalPX tariffs as prohibited market manipulative behavior. FERC did not
subject the Company to either of the show cause orders. FERC also issued an
order directing the FERC staff to investigate further whether market
participants who bid a price in excess of $250 per megawatt hour into markets
operated 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, we are 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. Our
Qualifying Facilities ("QF") contracts with Pacific Gas and Electric Company
("PG&E") provide that the CPUC has the authority to determine the appropriate
utility "avoided cost" to be used to set energy payments for certain QF
contracts by determining the short run avoided cost ("SRAC") energy price
formula. In mid 2000, our QF facilities elected the option set forth in Section
390 of the California Public Utilities Code, which provided QFs the right to
elect to receive energy payments based on the California Power Exchange ("PX")
market clearing price instead of the price determined by SRAC. Having elected
such option, we were paid based upon the PX zonal day-ahead clearing price ("PX
Price") from summer 2000 until January 19, 2001, when the PX ceased operating a
day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine
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. In
late 2000, the CPUC Commissioner assigned to this matter issued a proposed
decision to the effect that the PX Price was the appropriate price for energy
payments under the California Public Utilities Code but the CPUC has yet to
issue a final decision. Therefore, it is possible that the CPUC could order a
retroactive 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 requested that the CPUC set a briefing
schedule in the R.99-11-022 docket 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 alleged that refund liability be determined using the
methodology that has been developed thus far in the California Refund Proceeding
discussed above. On August 16, 2005, the Administrative Law Judge assigned to
hear the April 29 Motion issued a ruling setting October 11, 2005, as the date
for filing prehearing conference statements and October 17, 2005, as the date of
the prehearing conference. In our response, filed on October 11, 2005, we urged
that the April 29 Motion should be dismissed, but if dismissal were not granted,
then discovery, testimony and hearings would be required. The assigned
Administrative Law Judge has not yet issued a formal ruling following the
October 17, 2005 prehearing conference. We believe that the PX Price was the
appropriate price for energy payments and that the basis for any refund
liability based on the interim determination by the FERC in the California
Refund Proceeding is unfounded, but there can be no assurance that this will be
the outcome of the CPUC proceedings.
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Reliability Must Run Contracts with Geysers. The CAISO, the California
Electricity Oversight Board, the CPUC, PG&E, 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, 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 CAISO to meet local transmission reliability needs or to manage
transmission constraints. The Buyers Coalition asked FERC to find that the
availability payments under these RMR Contracts are not just and reasonable.
Geysers filed an answer to the complaint in November 2001. On June 3, 2005, FERC
issued an order dismissing the Buyers Coalition's complaint against all named
generation owners, including Geysers. On August 2, 2005, FERC issued an order
rejecting requests for rehearing of its order. The proceeding is now concluded
at FERC. On September 23, 2005, the Buyers Coalition (with the exclusion of the
CAISO) filed a Petition for Review with the United States Court of Appeals for
the District of Columbia Circuit, seeking review of FERC's order dismissing the
complaint.
15. Subsequent Events
On October 6, 2005, the Company completed the sale of its 561-megawatt
Ontelaunee Energy Center to LS Power Equity Partners for $225 million, less
transaction fees, costs and working capital adjustments of approximately $13.0
million. The Ontelaunee sale is the third of four planned power plant sales
announced by the Company in June 2005. Net proceeds from the sale of Ontelaunee
will be used in accordance with the Company's indentures. Upon its commitment to
a plan of divesture of Ontelaunee and in accordance with SFAS No. 144, the
Company recorded an impairment charge of $136.8 million in the three months
ended September 30, 2005. The sale of Ontelaunee closed October 6, 2005. This
impairment charge is reflected in discontinued operations in the three months
ended September 30, 2005. See Note 5 for more information.
In connection with the sale of Ontelaunee and in accordance with the
instruments governing its indebtedness, on October 6, 2005, CCFC LLC commenced
offers to purchase its outstanding secured term loans and notes in an amount up
to the net proceeds received from the Ontelaunee sale. The offer to purchase
term loans expired on October 28, 2005, and the offer to purchase notes expired
on November 4, 2005, without any term loans or notes having been tendered for
purchase.
On October 14, 2005, the Company's indirect subsidiary, CCFC LLC, issued
$300.0 million of 6-Year Redeemable Preferred Shares Due 2011 at LIBOR plus 950
basis points. Net proceeds from the offering of the Redeemable Preferred Shares
will be used as permitted by Calpine's existing bond indentures.
On October 14, 2005, CCFC LLC repurchased its $150.0 million in Class A
Redeemable Preferred Shares due February 13, 2006.
Repurchased $93.3 million of 8 1/2% Senior Notes due 2008 in October 2005,
in open market transactions for cash totaling $55.7 million, plus accrued
interest.
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
- 52 -
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 the exploitation of our geothermal
resource, (xi) uncertainties associated with estimates of geothermal 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) our ability to successfully
implement the various components of our strategic initiative to increase
liquidity, reduce debt and reduce operating costs, (xv) uncertainties associated
with estimates of sources and uses of cash, that actual sources may be lower and
actual uses may be higher than estimated, (xvi) implementation of our strategy
to expand our third party service businesses and diversify our fuel source,
(xvii) 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, (xviii)
present and possible future claims, litigation and enforcement actions, (xix)
effects of the application of regulations, including changes in regulations or
the interpretation thereof, and (xx) other risks identified in this report. You
should also carefully review the risks described in other reports that we file
with the Securities and Exchange Commission, including without limitation our
Annual Report on Form 10-K for the year ended December 31, 2004, and our Current
Report on Form 8-K filed with the SEC on July 1, 2005. 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 100 F Street, NE, Room 1580,
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 100 F Street, NE, Room 1580, 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.
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------------------------------------------
2005 2004 2005 2004
--------------- --------------- --------------- ----------------
(In thousands, except pricing data)
Power Plants:
E&S revenues:
Energy..................................................... $ 1,634,372 $ 1,133,557 $ 3,430,720 $ 2,814,915
Capacity................................................... 317,754 312,649 840,020 763,234
Thermal and other.......................................... 144,197 98,123 354,338 273,765
--------------- --------------- --------------- ---------------
Subtotal................................................... $ 2,096,323 $ 1,544,329 $ 4,625,078 $ 3,851,914
Spread on sales of purchased power (1)....................... 69,503 79,355 233,427 135,912
--------------- --------------- --------------- ---------------
Adjusted E&S revenues before mark-to-market
activities, net (non-GAAP)................................. $ 2,165,826 $ 1,623,684 $ 4,858,505 $ 3,987,826
MWh produced................................................. 28,709 26,604 68,240 64,357
All-in electricity price per MWh generated before
mark-to-market activities, net............................. $ 75.44 $ 61.03 $ 71.20 $ 61.96
- ----------
(table continues)
- 53 -
<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, 2005 and
2004, 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,
---------------------------------------------------------------------
2005 2004 2005 2004
--------------- --------------- --------------- ----------------
Total revenue............................................... $ 3,281,590 $ 2,411,733 $ 7,526,228 $ 6,466,332
Sales of purchased power for hedging and optimization (1)... 413,281 427,737 1,193,537 1,301,585
As a percentage of total revenue............................ 12.6% 17.7% 15.9% 20.1%
Sale of purchased gas for hedging and optimization.......... 696,850 423,733 1,574,067 1,258,441
As a percentage of total revenue............................ 21.2% 17.6% 20.9% 19.5%
Total COR................................................... 3,042,463 2,185,288 7,124,903 6,157,841
Purchased power expense for hedging and optimization (1).... 343,778 348,380 960,110 1,165,674
As a percentage of total COR................................ 11.3% 15.9% 13.5% 18.9%
Purchased gas expense for hedging and optimization.......... 724,351 429,373 1,623,692 1,243,781
As a percentage of total COR................................ 23.8% 19.6% 22.8% 20.2%
- ------------
<FN>
(1) On October 1, 2003, we adopted on a prospective basis 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" and netted certain purchases
of power against sales of purchased power. See Note 2 of the Notes to
Consolidated Condensed 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 CES risk management organization; (b) volatile
markets for electricity and natural gas, which prompt us to frequently adjust
our hedge positions by buying power and gas and reselling it; and (c) the
accounting requirements under SAB No. 101, "Revenue Recognition in Financial
Statements," and EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Agent," under which we show many of our hedging contracts on a
gross basis (as opposed to netting sales and cost of revenue).
Overview
Our core business and primary source of revenue is the generation and
delivery of electric power in North America. We provide power to our U.S. and
Canadian customers through the integrated development, 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 protect and enhance the value of our 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, repairing and operating power plants.
While we have been able to access the capital and bank credit markets since
2002, it has been on significantly different terms than before 2002. This has
been due to a range of factors, including uncertainty arising from the collapse
of Enron and a surplus supply of electric generating capacity in certain of our
market areas. These factors coupled with an extended period of decreased spark
spreads (the differential between power revenues and fuel costs) have adversely
impacted our capacity utilization rates, liquidity and earnings. Additionally,
natural gas prices have been volatile and, on average, have increased over the
last several years. The impact of rising natural gas prices on the Company is
discussed below. We recognize that the terms of capital available to us in the
future may not be attractive or our access to the capital markets may otherwise
be restricted. To protect against this possibility and due to current market
conditions, during the past several years we have scaled back our capital
expenditure program and have taken other steps to enhance our liquidity, reduce
our debt and otherwise conserve our capital resources. See "Capital
Availability" in Liquidity and Capital Resources below for a further discussion.
- 54 -
As part of our efforts to improve our financial strength, we announced a
strategic initiative in May 2005 aimed at:
o Optimizing the value of our core North American power plant portfolio
by selling certain power and natural gas assets to reduce debt and
lower annual interest cost, and to increase cash flow in future
periods. At September 30, 2005, we had completed the sales of Saltend
in the United Kingdom, Morris in Illinois and our interest in Grays
Ferry in Pennsylvania. Additionally, in October 2005, we completed the
sale of Ontelaunee and in July 2005, completed the sale of
substantially all of our remaining oil and natural gas assets. We are
in discussions with potential buyers for, or are considering, the sale
of additional assets. See Notes 8 and 15 of the Notes to Consolidated
Condensed Financial Statements for further information on these
transactions. There can be no assurance that the Company will be
successful in developing such alternative or additional sources of
fuel in the near term or otherwise.
o Taking actions to decrease operating and maintenance costs and
lowering fuel costs to improve the operating performance of our power
plants, which would boost operating cash flow and liquidity. In
addition, to further reduce cost, we have temporarily shut down two
power plants with negative cash flow, and are considering others,
until market conditions warrant starting back up. See also Note 12 of
the Notes to Consolidated Condensed Financial Statements for a
discussion of the restructuring of certain of our LTSAs.
o Reducing collateral requirements. On September 8, 2005, we and Bear
Stearns announced an agreement to form a new energy marketing and
trading venture to develop a third party customer business focused on
physical natural gas and power trading and related structured
transactions. Regulatory approval for this new entity was received on
October 31, 2005, and it is anticipated that operations will begin in
the fourth quarter of 2005. The transaction will include a $350
million credit intermediation agreement between CalBear, a new
subsidiary of Bear Stearns, and CES. It is anticipated that this
credit intermediation agreement will, among other things, positively
impact our working capital position by making possible the return of
cash and LCs currently posted as collateral.
o Reducing total debt, net of new construction financings, by more than
$3 billion from debt levels at year-end 2004, which we estimate would
provide $275 million of annual interest savings. We continue to
advance our May 2005 strategic initiative aimed at optimizing our
power plant portfolio, reducing debt and enhancing our financial
strength. While we continue to make progress toward our goal of
reducing total debt by more than $3 billion by year-end 2005 and
achieving an estimated $275 million of annual interest savings, the
timing of accomplishing this goal may be delayed into 2006. The cash
and other consideration needed to reduce debt by that amount will be a
function of the timing of asset sales, our ability to use proceeds of
such sales to reduce debt (we are currently involved in various
litigations with the holders of certain series of our outstanding
secured and unsecured bonds as described in Note 12 of the Notes to
Consolidated Condensed Financial Statements), the prices at which we
are able to repurchase debt and other factors. At September 30, 2005,
total consolidated debt was $17.2 billion, a reduction of $0.9 billion
from the $18.1 billion level at March 31, 2005, before the strategic
initiative was announced. Excluding the effect of new construction
financing of $178.7 million, we have reduced debt by approximately
$1.1 billion during this period. However, regardless of whether or not
the specific $3 billion debt reduction goal can be achieved by
December 31, 2005, we remain committed to achieving that goal as soon
as practicable.
In addition, as noted above, we seek to identify opportunities to capture
value in the skills and knowledge that we have developed, not only to improve
the operating performance of our facilities but also to develop new sources of
revenues by, for example, utilizing our hedging and optimization skills to
develop the CalBear business and by expanding our third-party combustion turbine
component parts and retail and maintenance services businesses. We are also
actively exploring possible alternative sources of natural gas (such as LNG and
Alaskan pipeline projects) to increase the natural gas supply in the continental
United States, as well as other sources of fuel for our natural gas-fired
generation facilities, such as projects to convert pet coke, an oil refinery
waste product, into gas suitable for combustion in our gas turbines. There can
be no assurance that we will be successful in developing such alternative or
additional sources of fuel in the near term or otherwise.
Other key opportunities and challenges for us include:
o preserving and enhancing our liquidity while spark spreads are
depressed,
- 55 -
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 managing our exposure to volatile natural gas prices.
The price of natural gas has been volatile over the last several years and
has, on average, increased. We are one of the largest gas consumers (if not the
largest) in the United States, and therefore, we carefully evaluate and seek to
optimally manage our gas position. In markets where gas-fired power generation
is "on the margin" (based on the profile of available capacity, incremental
electricity generation is likely to be produced by natural gas plants), and the
Company has open generation capacity for sale, higher natural gas prices can,
and do, produce higher spark spreads for us when dispatched due to our
efficient, low heat rate fleet of generation plants. In other situations, the
impact of higher gas prices on us is neutral (or potentially positive), such as
in cases where we have entered into tolling arrangements or heat rate index
contracts with customers. In tolling arrangements, the customer is responsible
for buying and delivering natural gas to one of our generating plants, and we
receive a tolling payment to convert the customer's natural gas into
electricity. In heat rate index contracts, the price for energy produced is
priced by multiplying a contractual heat rate times the market fuel price over
the contract term. To the extent that the contract heat rate is higher than our
actual generation heat rate, we would, and do, realize improved spark spreads
from higher natural gas prices. However, in situations where we have sold fixed
price power and do not maintain a 100% hedged gas position, higher natural gas
prices can, and do, reduce our spark spread to the extent of any short
fixed-price gas position. In the third quarter of 2005, following the sale of
our remaining oil and gas assets in early July 2005, we were thereafter short
fixed-price gas and could remain in a short position for some period of time
until the position can be rebalanced.
In addition, by eliminating the equity gas benefit that we had enjoyed due
to the fact that our costs of producing natural gas were significantly lower
than natural gas prices in recent years through the sale of our remaining oil
and gas assets to Rosetta in July 2005, we expect an increase in the future
effective fuel expense (and lower spark spread) for our fleet of gas-fired
generating plants. Also, we expect that purchasing additional volumes from third
party producers will increase our requirements to post collateral or prepay for
gas. However, the negative impacts on spark spread and gross profit (loss) are
expected to be offset to some extent by lower interest expense in the future to
the extent the proceeds of the sale are able to be used to repay debt. We also
expect to use other hedging approaches in managing our natural gas requirements
to compensate for the loss of the natural hedge position that equity gas had
afforded us. In the past, when we sold fixed price power, we could use our
equity gas reserves as a hedge against rising gas prices. Other techniques have
included purchase of fixed-for-floating gas price swap contracts, purchasing
physical gas on a fixed-price basis, or potentially buying back fixed price
power contracts. In the future we will be more reliant on these other
techniques, the use of which may be limited by our current credit constraints.
From a physical gas purchase perspective, we will be purchasing Rosetta's
California production at market prices under industry standard margining
provisions. We estimate that our collateral requirements at the date of sale
increased by approximately $25 million for a typical payment cycle. From a fixed
price gas exposure perspective, we will not have any fixed price hedges in place
with Rosetta, so our position will need to be managed with financial swaps and
fixed price physical gas purchases. In addition, we may use proceeds of the sale
to purchase natural gas assets as permitted by our indentures.
Overview of Results -- In the third quarter of 2005, generation volume was
up 7.9% from the prior year due primarily to four new facilities and one
expansion project coming online in the twelve months ended September 30, 2005.
Also, spark spread increased by approximately 6% in the same period. Even with
the new capacity, our average baseload capacity factor for the three months
ended September 30, 2005, was 54.0% compared to 55.4% in the prior year period.
Demand was stronger in virtually all of the Company's key markets, except
Northern California due to below normal temperatures in September 2005, and
market on-peak spark spreads improved significantly in the third quarter of
2005. However, off-peak market spark spreads did not show similar improvements.
Also, we estimate that our spark spread margin was reduced in the quarter as a
result of being in a short fixed-price gas position following the sale of our
remaining oil and gas assets in July 2005. We may be susceptible to diminished
spark spreads when natural gas prices rise until we are ablt to rebalance our
fixed-price gas position. Further, in the 12 months ended September 30, 2005,
average natural gas prices (with Henry Hub delivery) increased by 147% from
$4.99 per million BTU to $12.35 per million BTU. While this current price spike
is largely attributable to the damage caused by hurricane's Katrina and Rita in
August and September 2005, natural gas prices historically had a winter peak in
demand due to home heating usage; however, partly as a result of increased use
as a fuel for electric power generation, demand is less seasonal and is
developing a summer peak in addition to the winter peak.
- 56 -
Set forth below are the Results of Operations for the three and nine months
ended September 30, 2005 and 2004, which reflect reclassifications for
discontinued operations. See Note 8 of the Notes to Consolidated Condensed
Financial Statements.
Results of Operations
Three Months Ended September 30, 2005, Compared to Three Months Ended
September 30, 2004
(In millions unless indicated otherwise, except for unit pricing
information, percentages and MW volumes). In the comparative tables below,
increases in revenue/income or decreases in expense (favorable variances) are
shown without brackets. Decreases in revenue/income or increases in expense
(unfavorable variances) are shown with brackets.
Revenue
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Total revenue.............................................................. $ 3,281.6 $ 2,411.7 $ 869.9 36.1%
The change in total revenue is explained by category below.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Electricity and steam revenue.............................................. $ 2,096.3 $ 1,544.3 $ 552.0 35.7%
Transmission sales revenue................................................. 1.9 4.4 (2.5) (56.8)%
Sales of purchased power for hedging and optimization...................... 413.3 427.7 (14.4) (3.4)%
------------ ------------ ------------
Total electric generation and marketing revenue......................... $ 2,511.5 $ 1,976.4 $ 535.1 27.1%
============ ============ ============
Electricity and steam revenue increased as we completed the construction
and brought into operation four additional baseload power facilities and one
expansion project subsequent to September 30, 2004, and realized an increase in
our average electric price before the effects of hedging, balancing and
optimization, from $58.05/MWh for the three months ended September 30, 2004, to
$73.02/MWh for the same period in 2005. Average total megawatts in operation of
our consolidated plants increased by 7.8% to 26,126 MW, which was consistent
with our increase in total generation of 7.9%. However, average baseload
megawatts in operation increased by 8.8% compared to an increase of only 6.1%
for baseload generation. The increase in generation, resulting in a drop in our
baseload capacity factor dropped to 54.0% in the three months ended September
30, 2005, from 55.4% in the three months ended September 30, 2004. This was
primarily due to the increased occurrence of unattractive off-peak market spark
spreads in certain areas reflecting oversupply conditions which are expected to
gradually improve over the next several years, but which caused us to cycle-off
certain of our merchant plants without contracts in off-peak hours.
We purchase transmission capacity so that power can move from our plants to
our customers. Transmission capacity can be purchased on a long term basis and,
in many of the markets in which the company operates, can be resold if we do not
need it and some other party can use it. If the generation from our plants is
less than we anticipated when we purchased the transmission capacity, we can and
do realize revenue by selling the unused portion of the transmission capacity.
We also, in many cases, bill our customers for transmission costs that we
incur in serving their accounts. This is especially true in the case of many of
our retail contracts. When we bill our customers for transmission expenses
incurred on their behalf we recognize these billings as a component of
transmission revenue. For the three months ended September 30, 2005 as compared
to the same period in 2004 transmission revenues have declined as we have seen a
reduction in transmission billings relating our retail customers.
Sales of purchased power for hedging and optimization decreased in the
three months ended September 30, 2005, due primarily to lower volumes which were
partially offset by higher prices, as compared to the same period in 2004.
- 57 -
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Oil and gas sales.......................................................... $ -- $ 2.7 $ (2.7) (100.0)%
Sales of purchased gas for hedging and optimization........................ 696.9 423.7 273.2 64.5%
------------ ------------ ------------
Total oil and gas production and marketing revenue...................... $ 696.9 $ 426.4 $ 270.5 63.4%
============ ============ ============
We reclassified our remaining oil and gas operations, which were sold in
July 2005, to discontinued operations in the quarter ended June 30, 2005, upon
our commitment to a plan of divesture of the component. Activity in prior years
relates to minor assets sold in prior years that did not meet the criteria for
reclassification to discontinued operations at the time of sale. See Note 8 of
the Notes to Consolidated Condensed Financial Statements for more information.
Sales of purchased gas for hedging and optimization increased during 2005
due primarily to higher liquidation prices of natural gas and a moderate
increase in volumes compared to the same period in 2004.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Mark-to-market activities, net............................................. $ 40.9 $ (5.2) $ 46.1 886.5%
Mark-to-market activities, which are shown on a net basis, result from
general market price movements against our open commodity derivative positions,
These commodity positions represent a small portion of our overall commodity
contract position.
The net gain from mark-to-market activities in the three months ended
September 30, 2005, as compared to the same period in 2004 is due primarily to
gains on our Deer Park transaction which are recorded on a mark-to-market basis,
and gains attributable to gas contracts that lost hedge accounting eligibility
for the quarter. In order to qualify for hedge accounting under SFAS No. 133,
price movements in the hedge contract and the hedged transaction must move in a
manner whereby changes in value of the hedge contract and hedged transaction
sufficiently offset. As a result of significant volatility in the gas markets,
certain of our gas contracts did not meet these requirements and we recorded
approximately $18.3 million in mark-to-market gains that would have otherwise
been recorded through other comprehensive income.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Other revenue.............................................................. $ 32.4 $ 14.0 $ 18.4 131.4%
Other revenue increased due primarily to higher revenues at PSM associated
with sales of gas turbine components and at TTS for gas turbine maintenance
services and the sale of spare turbine parts and components.
Cost of Revenue
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Cost of revenue............................................................ $ 3,042.5 $ 2,185.3 $ (857.2) (39.2)%
- 58 -
The increase in total cost of revenue is explained by category below.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Plant operating expense.................................................... $ 180.3 $ 160.0 $ (20.3) (12.7)%
Transmission purchase expense.............................................. 23.1 22.7 (0.4) (1.8)%
Royalty expense............................................................ 10.0 8.3 (1.7) (20.5)%
Purchased power expense for hedging and optimization....................... 343.8 348.4 4.6 1.3%
------------ ------------ ------------
Total electric generation and marketing expense......................... $ 557.2 $ 539.4 $ (17.8) (3.3)%
============ ============ ============
Plant operating expense increased primarily due to four additional baseload
power facilities and one expansion project in operation subsequent to September
30, 2004, which was partially offset by lower major maintenance spending versus
prior year, largely due to the timing of such work.
In many cases, we incur transmission costs that result from serving the
accounts of our customers. This is especially true in the case of many of our
retail contracts. When we incur transmission expenses on behalf of our customers
we recognize these amounts as a component of transmission purchase expense. For
the three months ended September 30, 2005 as compared to the same period in 2004
transmission purchase expenses have declined as we have seen a reduction in
transmission purchases relating to our retail customers.
Royalty expense increased primarily due to an increase in electric revenues
at The Geysers geothermal plants and an increase in contingent purchase price
payments to the previous owners of our Texas City and Clear Lake power plants.
At The Geysers, royalties are paid mostly as a percentage of geothermal
electricity revenues and royalties associated with Texas City and Clear Lake are
based on a percentage of gross revenues earned at the plants.
Purchased power expense for hedging and optimization decreased during the
three months ended September 30, 2005, as compared to the same period in 2004
due primarily to a reduction in volumes which wer partially offset by higher
prices, as compared to the same period in 2004.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Oil and gas operating expense.............................................. $ 1.4 $ 1.8 $ 0.4 22.2%
Purchased gas expense for hedging and optimization......................... 724.3 429.4 (294.9) (68.7)%
------------ ------------ ------------
Total oil and gas operating and marketing expense....................... $ 725.7 $ 431.2 $ (294.5) (68.3)%
============ ============ ============
The Company reclassified its remaining oil and gas operations to
discontinued operations ("held for sale") in the three months ended June 30,
2005. Remaining activity in continuing operations relates primarily to gas
pipeline activities which were not sold and activity in prior years also
includes the results of minor assets sold in prior years that did not meet the
criteria for reclassification to discontinued operations at the time of sale.
See Note 8 of the Notes to Consolidated Condensed Financial Statements for more
information.
Purchased gas expense for hedging and optimization increased during the
three months ended September 30, 2005, due to higher natural gas prices and
higher volumes as compared to the same period in 2004.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Fuel expense............................................................... $ 1,567.5 $ 1,052.3 $ (515.2) (49.0)%
Fuel expense increased during the three months ended September 30, 2005, as
compared to the same period in 2004 due primarily to higher natural gas prices
and an increase of 7.9% in generation due largely to the addition of four
baseload power facilities and one expansion project to our consolidated
- 59 -
operating portfolio subsequent to September 30, 2004. Our average fuel expense
before the effects of hedging, balancing and optimization increased by 41% from
$5.88/MMBtu for the three months ended September 30, 2004 to $8.28/MMBtu for the
same period in 2005.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Depreciation, depletion and amortization expense........................... $ 131.0 $ 117.4 $ (13.6) (11.6)%
Depreciation, depletion and amortization expense increased primarily due to
the additional power facilities in consolidated operations subsequent to
September 30, 2004.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Operating lease expense.................................................... $ 28.8 $ 25.8 $ (3.0) (11.6)%
Operating lease expense increased from the prior year due to an additional
non-cash adjustment, which was necessary due to a revision in our estimated cost
to dismantle our Watsonville facility at the end of the lease term in 2010.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Other cost of revenue...................................................... $ 32.2 $ 19.2 $ (13.0) (67.7)%
Other cost of revenue increased during the three months ended September 30,
2005, as compared to the same period in 2004, due to increased gas turbine
maintenance services activity and spare turbine parts and component sales at TTS
and increased gas turbine component sales by PSM.
(Income)/Expenses
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
(Income) loss from unconsolidated investments.............................. $ (5.4) $ 11.2 $ 16.6 148.2%
The increase in income was primarily due to an increase in income from the
Acadia PP investment (due mostly to lower major maintenance costs and decreased
LTSA costs), and the non-recurrence of losses recorded in 2004 from our
investment in the AELLC power plant. We ceased to recognize our share of the
operating results of AELLC as we began to account for our investment in AELLC
using the cost method following loss of effective control when AELLC filed for
bankruptcy protection in November 2004. In September 2004 prior to AELLC filing
for bankruptcy protection, we recognized our share of an adverse jury award
related to a dispute with IP. Our share of that expense was $11.6.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Equipment cancellation and impairment cost................................. $ 0.8 $ 7.8 $ 7.0 89.7%
During the three months ended September 30, 2005, equipment cancellation
and asset impairment charge decreased by $7.0 as compared to the same period in
2004 primarily as a result of two non-recurring charges we incurred during the
third quarter of 2004. During the three months ended September 30, 2004, we
- 60 -
incurred a loss of $4.3 recognized in connection with the impairment charge for
one HRSG and a loss on the sale of 12 tube bundles in the amount of $3.5.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Long-term service agreement cancellation charge............................ $ 0.6 $ 4.0 $ 3.4 85.0%
During the three months ended September 30, 2004, we recorded charges of
$7.6 related to the cancellation and settlement of four LTSAs with Siemens
Westinghouse. During the three months ended September 30, 2005, we retroactively
reclassified $3.6 of these charges to discontinued operations due to our
commitment to a plan to divest the Ontelaunee Energy Center.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Project development expense................................................ $ 10.1 $ 3.4 $ (6.7) (197.1)%
Project development expense increased by $6.7 during the three months ended
September 30, 2005, compared to the same period in 2004 primarily due to an
increase of $6.3 in site preservation costs related to projects whose
development/construction has been suspended.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Research and development expense........................................... $ 3.3 $ 4.0 $ 0.7 17.5%
Research and development expense decreased during the three months ended
September 30, 2005, as compared to the same period in 2004 primarily due to the
timing of personnel expenses and consulting fees related to new research and
development programs and testing at PSM.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Sales, general and administrative expense.................................. $ 54.6 $ 53.8 $ (0.8) (1.5)%
Sales, general and administrative expense increased during the three months
ended September 30, 2005, primarily due to an increase in information technology
and employee compensation costs offset by decreases in consulting fees and
facilities costs.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Interest expense........................................................... $ 381.0 $ 285.4 $ (95.6) (33.5)%
Interest expense increased primarily as a result of higher average interest
rates and lower capitalization of interest expense. Our average interest rate
increased from 8.4% for the three months ended September 30, 2004, to 9.4% for
the three months ended September 30, 2005, primarily due to the impact of rising
U.S. interest rates and their effect on our existing variable rate debt
portfolio and higher average interest rates incurred on new debt instruments
that were entered into to replace and/or refinance existing debt instruments
during 2005. Interest capitalized decreased from $86.7 for the three months
ended September 30, 2004, to $36.0 for the three months ended September 30,
2005, as new plants entered commercial operations (at which point capitalization
of interest expense ceases) and because of suspended capitalization of interest
on three partially completed construction projects. During the three months
ended September 30, 2005, (i) interest expense related to our Senior Notes,
contingent convertible notes, and term loans increased by $7.4; (ii) interest
expense related to our CalGen subsidiary increased $11.4; (iii) interest expense
related to our construction/project financing increased by $17.3; (iv) interest
expense related to our CCFC I subsidiary increased by $3.8; and (v) interest
expense related to preferred interests increased by $12.2 primarily due to the
June 2005 closing of the $15.5 offering of redeemable preferred securities by
our indirect subsidiary, Metcalf, the August 2005 closing of the $150 offering
- 61 -
of redeemable preferred securities by our indirect subsidiary, CCFC LLC, the
October 2004 closing of the $360 offering of redeemable preferred securities by
our indirect subsidiary, Calpine Jersey I, and the $260 offering on January 31,
2005, of redeemable preferred securities by our indirect subsidiary, Calpine
Jersey II (the Calpine Jersey I and Calpine Jersey II securities were
repurchased with proceeds from the sale of Saltend in July 2005). These interest
cost increases are partially offset by a decrease of $15.6 in interest expense
on the convertible debentures payable to the Calpine Capital Trusts, which have
been redeemed.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Interest (income).......................................................... $ (26.6) $ (17.0) $ 9.6 56.5%
Interest (income) increased during the three months ended September 30,
2005, due primarily to higher interest earned on margin deposits and collateral
posted to secure letters of credit and due to higher interest rates.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Minority interest expense.................................................. $ 11.0 $ 10.0 $ (1.0) (10.0)%
Minority interest expense increased during the three months ended September
30, 2005, as compared to the same period in 2004 primarily due to an increase in
income at CPLP, which is 70% owned by CPIF. The variance is largely due to an
increase in steam revenue at the Island Cogen plant which was driven by higher
gas prices; the price of gas is a component of the steam revenue calculation.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
(Income) from repurchase of debt........................................... $ (15.5) $ (167.2) $ (151.7) (90.7)%
The decrease in income from repurchase of debt is due to considerably
higher volumes of Senior Notes repurchased during the three months ended
September 30, 2004, compared to the same period in 2005. See Note 7 of the Notes
to Consolidated Condensed Financial Statements for further information.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Other expense (income), net................................................ $ 50.3 $ 22.4 $ (27.9) (124.6)%
Other expense increased for the three months ended September 30, 2005,
compared to the same period in 2004, primarily due to a $31.5 increase in
non-cash foreign currency transaction losses. See the "foreign currency
transaction gain (loss)" discussion within "Financial Market Risks" for further
information.
- 62 -
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Provision (benefit) for income taxes....................................... $ 17.5 $ (20.3) $ (37.8) (186.2)%
During the three months ended September 30, 2005, our tax provision
increased by $37.8 as compared to the benefit in the three months ended
September 30, 2004, despite the fact that our pre-tax loss increased $233.5 in
2005. The effective tax rate increased to (7.8)% in 2005 compared to (237.6)% in
the same period in 2004 largely due to a valuation allowance recorded on certain
deferred tax assets associated with CCFC which had the effect of reducing the
tax benefit on our pre-tax loss by approximately $143.4. The tax rates on
continuing operations for the three months ended September 30, 2004, have been
restated to reflect the reclassification to discontinued operations of certain
tax expense related to the sale of oil and gas reserves, Saltend, and the Morris
and Ontelaunee power plants. See Note 8 of the Notes to Consolidated Condensed
Financial Statements for further information.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Discontinued operations, net of tax provision.............................. $ 25.7 $ 112.2 $ (86.5) (77.1)%
During the three months ended September 30, 2005, discontinued operations
activity primarily consisted of the pre-tax gain on the sale of Saltend of $26.3
and the pre-tax gain on the sale of substantially all of our remaining oil and
gas assets of $342.8; both dispositions closed in July 2005. Offsetting these
gains is a pre-tax impairment charge of $136.8 related to the pending sale of
Ontelaunee, which met the discontinued operations criterion as of September 30,
2005 under SFAS No. 144. On a pre-tax basis, we recorded income from
discontinued operations for the three months ended September 30, 2005 of $196.3.
Our effective tax rate on discontinued operations for the three months ended
September 30, 2005, however, was 86.9% due primarily to a large tax return gain
on the sale of Saltend and, as a consequence, our after-tax gain from
discontinued operations was only $25.7. Discontinued operations for the three
months ended September 30, 2004, consisted primarily of a pre-tax gain from the
sale of our Canadian and U.S. Rocky Mountain oil and gas assets of $203.5. On a
net of tax basis, income from discontinued operations for the three months ended
September 30, 2004, was $112.2, based on an effective tax rate of 47.7%.
Three Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Net income (loss).......................................................... $ (216.7) $ 141.1 $ (357.8) (253.6)%
For the three months ended September 30, 2005, we reported revenue of $3.3
billion, representing an increase of 36% over the same period in the prior year.
Including the discontinued operations discussed below, we recorded a net loss
per share of $0.45, or a net loss of $216.7, compared to net income per share of
$0.32, or net income of $141.1, for the same quarter in the prior year.
For the three months ended September 30, 2005, our average capacity in
operation for consolidated projects in continuing operations increased by 7.8%
to 26,126 megawatts. Generation volume was up 7.9% from the prior year as we
generated approximately 28.7 million megawatt-hours, which equated to a baseload
capacity factor of 54.0%, and realized an average spark spread of $20.74 per
megawatt-hour. For the same period in 2004, we generated 26.6 million
megawatt-hours, which equated to a baseload capacity factor of 55.4%, and
realized an average spark spread of $21.15 per megawatt-hour.
Gross profit increased by $12.7 to $239.1 in the three months ended
September 30, 2005, compared to the same period in the prior year as total spark
spread margin increased by $32.7 period-to-period. We estimate that our spark
spread margin was reduced in the quarter as a result of being in a short
fixed-price gas position following the sale of our oil and gas assets. Our
overall short fixed-price gas position makes us susceptible to diminished spark
spreads when natural gas prices rise and will continue to do so until our
- 63 -
position is rebalanced. Total spark spread margin did not increase in line with
the increases in plant operating expense, depreciation, other cost of revenue
items and interest expense.
During the three months ended September 30, 2005, financial results were
positively impacted by $15.5 of income recorded from repurchase of debt, but
this was lower by $151.6 than the gain recorded from repurchase of debt in the
comparable period in 2004. Costs to cancel equipment orders and long-term
service agreements totaled $1.3 in 2005, compared to $11.8 in the prior year,
and income from unconsolidated investments was also favorable, by $16.6 versus
the prior year, primarily because we recorded $11.6 of loss in the comparable
period of 2004 associated with an unfavorable jury award at AELLC. However, in
the third quarter of 2005, we recorded $6.7 higher project development expense
compared to the prior year due mostly to higher preservation costs at suspended
projects, and interest expense increased by $95.6 between periods primarily due
to lower capitalization of interest expense, as fewer plants were in active
construction, and due to an increase in the average interest rate.
Other expense of $50.3 for the three months ended September 30, 2005 was
unfavorable by $27.9, compared to other expense of $22.4 for the three months
ended September 30, 2004 due to an increase of $31.5 in non-cash foreign
currency transaction losses.
In the three months ended September 30, 2005 we recorded a pre-tax gain
from discontinued operations of $196.3. However, our effective tax rate on
discontinued operations was 86.9% due primarily to a large tax return gain on
the sale of Saltend and, as a consequence, our after-tax gain from discontinued
operations was only $25.7. Income from discontinued operations included gains on
the sale of our remaining oil and gas assets and Saltend , both of which closed
in July 2005, and an impairment charge associated with Ontelaunee, which was
classified as held for sale at September 30, 2005 and closed in October 2005.
Discontinued operations also includes the operating results until the respective
sales dates for those entities and the Morris power plant, for which we recorded
an impairment charge in the second quarter of 2005 and which was sold in the
third quarter of 2005. For the three months ended September 30, 2004, we
recorded a net after-tax gain of $112.2 million in discontinued operations from
the sales of our Canadian and U. S. Rocky Mountain oil and gas assets.
Nine Months Ended September 30, 2005, Compared to Nine Months Ended September
30, 2004
(In millions unless indicated otherwise, except for unit pricing
information, percentages and MW volumes). In the comparative tables below,
increases in revenue/income or decreases in expense (favorable variances) are
shown without brackets. Decreases in revenue/income or increases in expense
(unfavorable variances) are shown with brackets.
Revenue
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Total revenue.............................................................. $ 7,526.2 $ 6,466.3 $ 1,059.9 16.4%
The change in total revenue is explained by category below.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Electricity and steam revenue.............................................. $ 4,625.1 $ 3,851.9 $ 773.2 20.1%
Transmission sales revenue................................................. 8.8 14.2 (5.4) (38.0)%
Sales of purchased power for hedging and optimization...................... 1,193.5 1,301.6 (108.1) (8.3)%
------------ ------------ ------------
Total electric generation and marketing revenue......................... $ 5,827.4 $ 5,167.7 $ 659.7 12.8%
============ ============ ============
Electricity and steam revenue increased as we completed construction and
brought into operation four new baseload power plants and one expansion project
completed subsequent to September 30, 2004, and realized an increase in our
average electric price before the effects of hedging, balancing and
optimization, from $ 59.85/ MWh for the nine months ended September 30, 2004, to
$ 67.78/ MWh for the same period in 2005. Average megawatts in operation of our
consolidated plants increased by 13.2% to 25,079 MW while generation increased
by 6.0%, resulting in a drop in our baseload capacity factor to 45.9% in the
- 64 -
nine months ended September 30, 2005, from 50.1% in the nine months ended
September 30, 2004. This was primarily due to the increased occurrence of
unattractive off-peak market spark spreads in certain areas reflecting
oversupply conditions which are expected to gradually improve over the next
several years, but which caused us to cycle-off certain of our merchant plants
without contracts in off-peak hours.
We purchase transmission capacity so that power can move from our plants to
our customers. Transmission capacity can be purchased on a long term basis and,
in many of the markets in which the company operates, can be resold if the
Company does not need it and some other party can use it. If the generation from
our plants is less than we anticipated when we purchased the transmission
capacity, we can realize revenue by selling the unused portion of the
transmission capacity.
Sales of purchased power for hedging and optimization decreased in the nine
months ended September 30, 2005, due primarily to lower volumes which were
partially offset by higher prices, as compared to the same period in 2004.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Oil and gas sales.......................................................... $ -- $ 4.7 $ (4.7) (100.0)%
Sales of purchased gas for hedging and optimization........................ 1,574.1 1,258.4 315.7 25.1%
------------ ------------ ------------
Total oil and gas production and marketing revenue...................... $ 1,574.1 $ 1,263.1 $ 311.0 24.6%
============ ============ ============
We reclassified our remaining oil and gas operations, which were sold in
July 2005, to discontinued operations in the nine months ended September 30,
2005. Activity in prior years relates to minor assets sold in prior years that
did not meet the criteria for reclassification to discontinued operations at the
time of sale. See Note 8 of the Notes to Consolidated Condensed Financial
Statements for more information.
Sales of purchased gas for hedging and optimization increased during 2005
due primarily to significantly higher natural gas prices and volumes compared to
the same period in 2004.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Mark-to-market activities, net............................................. $ 40.2 $ (15.3) $ 55.5 362.7%
Mark-to-market activities, which are shown on a net basis, result from
general market price movements against our open commodity derivative positions,
These commodity positions represent a small portion of our overall commodity
contract position.
The net gain from mark-to-market activities in the nine months ended
September 30, 2005, as compared to the same period in 2004 is due primarily to
gains on our Deer Park transaction which are recorded on a mark-to-market basis,
and gains attributable to gas contracts that lost hedge accounting eligibility
for the quarter. In order to qualify for hedge accounting under SFAS No. 133,
price movements in the hedge contract and the hedged transaction must move in a
manner whereby changes in value of the hedge contract and hedged transaction
sufficiently offset. As a result of significant volatility in the gas markets,
certain of our gas contracts did not meet these requirements and we recorded
approximately $18.3 million in mark-to-market gains that would have otherwise
been recorded through other comprehensive income.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Other revenue.............................................................. $ 84.6 $ 50.8 $ 33.8 66.5%
Other revenue increased due primarily to higher revenues at PSM associated
with sales of gas turbine components and at TTS for gas turbine maintenance
services and spare turbine parts and component sales.
- 65 -
Cost of Revenue
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Cost of revenue............................................................ $ 7,124.9 $ 6,157.8 $ (967.1) (15.7)%
The increase in total cost of revenue is explained by category below.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Plant operating expense.................................................... $ 555.4 $ 522.2 $ (33.2) (6.4)%
Transmission purchase expense.............................................. 63.8 53.8 (10.0) (18.6)%
Royalty expense............................................................ 28.3 21.1 (7.2) (34.1)%
Purchased power expense for hedging and optimization....................... 960.1 1,165.7 205.6 17.6%
------------ ------------ ------------
Total electric generation and marketing expense......................... $ 1,607.6 $ 1,762.8 $ 155.2 8.8%
============ ============ ===========
Plant operating expense increased primarily due to four additional baseload
power facilities and one expansion project that achieved commercial operation
subsequent to September 30, 2004 and the timing of regular maintenance
activities, partially offset by a decrease in major maintenance spending, which
was also affected by timing differences versus prior year.
In many cases, we incur transmission costs that result from serving the
accounts of our customers. This is especially true in the case of many of our
retail contracts. When we incur transmission expenses on behalf of our customers
we recognize these amounts as a component of transmission purchase expense. For
the nine months ended September 30, 2005 as compared to the same period in 2004
transmission purchase expenses have declined as we have seen a reduction in
transmission purchases relating to our retail customers.
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 owners of the Texas City and Clear Lake power
plants, which are based on a percentage of gross revenues at the plants. At The
Geysers, royalties are paid mostly as a percentage of geothermal electricity
revenues.
Purchased power expense for hedging and optimization decreased during the
nine months ended September 30, 2005, as compared to the same period in 2004 due
primarily to lower volumes which were partially offset by higher prices, as
compared to the same period in 2004.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Oil and gas operating expense.............................................. $ 4.3 $ 5.8 $ 1.5 25.9%
Purchased gas expense for hedging and optimization......................... 1,623.7 1,243.8 (379.9) (30.5)%
------------ ------------ ------------
Total oil and gas operating and marketing expense....................... $ 1,628.0 $ 1,249.6 $ (378.4) (30.3)%
============ ============ ============
We reclassified our remaining oil and gas operations, which were sold in
July 2005, to discontinued operations in the nine months ended September 30,
2005. Remaining activity in continuing operations relates primarily to gas
pipeline activities which were not sold and activity in prior years also
includes the results of minor assets sold in prior years that did not meet the
criteria for reclassification to discontinued operations at the time of sale.
See Note 8 of the Notes to Consolidated Condensed Financial Statements for more
information.
Purchased gas expense for hedging and optimization increased during the
nine months ended September 30, 2005, due to significantly higher natural gas
prices and higher volumes as compared to the same period in 2004.
- 66 -
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Fuel expense............................................................... $ 3,336.2 $ 2,671.9 $ (664.3) (24.9)%
Fuel expense increased during the nine months ended September 30, 2005, as
compared to the same period in 2004 due primarily to higher natural gas prices
and an increase of 6.0% in generation due largely to the addition of four
additional baseload power facilities and one expansion project to our
consolidated operating portfolio subsequent to September 30, 2004. Our average
fuel expense before the effects of hedging, balancing and optimization increased
by 23% from $6.01/MMBtu for the nine months ended September 30, 2004 to
$7.39/MMBtu for the same period in 2005.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Depreciation, depletion and amortization expense........................... $ 371.3 $ 324.9 $ (46.4) (14.3)%
Depreciation, depletion and amortization expense increased primarily due to
the five additional power facilities in consolidated operations subsequent to
September 30, 2004.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Operating lease expense.................................................... $ 79.1 $ 80.6 $ 1.5 1.9%
Operating lease expense decreased from the prior year due to the
restructuring of the King City lease in May 2004. After the restructuring we
began to account for the King City lease as a capital lease. As a result, we
stopped incurring operating lease expense at that facility and instead began to
incur depreciation and interest expense. Partially offsetting this decrease was
an increase in operating lease expense due to upward revisions in our estimated
dismantlement costs at our Watsonville facility at the end of the lease term in
2010.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Other cost of revenue...................................................... $ 102.5 $ 68.2 $ (34.3) (50.3)%
Other cost of revenue increased during the nine months ended September 30,
2005, as compared to the same period in 2004, due primarily to higher volumes of
parts sales at PSM and TTS and high volumes of services work and spare turbine
parts and component sales at TTS.
(Income)/Expenses
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
(Income) loss from unconsolidated investments.............................. $ (14.6) $ 12.2 $ 26.8 219.7%
The increase in income was primarily due to an increase in income from the
Acadia PP investment (mostly due to lower major maintenance costs), and the
non-recurrence of losses recorded in 2004 from our investment in the AELLC power
plant. We ceased to recognize our share of the operating results of AELLC as we
- 67 -
began to account for our investment in AELLC using the cost method following
loss of effective control when AELLC filed for bankruptcy protection in November
2004. In September 2004, we recognized our share of AELLC's adverse jury verdict
related to a dispute with International Paper of approximately $11.6.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Equipment cancellation and impairment cost................................. $ 0.7 $ 10.2 $ 9.5 93.1%
During the nine months ended September 30, 2005, equipment cancellation and
asset impairment charge decreased by $9.5 as compared to the same period in 2004
primarily as a result of three non-recurring charges we incurred during 2004.
During the nine months ended September 30, 2004, we incurred $2.3 in connection
with the termination of a purchase contract for HRSG components, $4.3 in
connection with the impairment charge for one HRSG and a loss on the sale of 12
tube bundles in the amount of $3.5.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Long-term service agreement cancellation charge............................ $ 34.4 $ 4.0 $ (30.4) (760.0)%
During the nine months ended September 30, 2005, we recorded charges of
$33.8 related to the cancellation of nine LTSAs with GE as part of a
restructuring of our service relationship. Additionally, we revised our previous
estimate and recorded an additional $0.6 in charges related to previously
cancelled LTSAs with Siemens Westinghouse.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Project development expense................................................ $ 71.6 $ 15.1 $ (56.5) (374.2)%
Project development expense increased by $56.5 during the nine months ended
September 30, 2005 compared to the same period in 2004 primarily due to a charge
of $44.8 to write off three projects in suspended development and $12.3 in site
preservation costs related to four projects whose development/construction has
been suspended.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Research and development expense........................................... $ 15.5 $ 12.9 $ (2.6) (20.2)%
Research and development expense increased during the nine months ended
September 30, 2005, as compared to the same period in 2004 primarily due to
increased personnel expense, and consulting fees related to new research and
development programs and testing at PSM.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Sales, general and administrative expense.................................. $ 176.3 $ 156.0 $ (20.3) (13.0)%
Sales, general and administrative expense increased during the nine months
ended September 30, 2005, primarily due to an increase in legal fees and the
reclassification of $7.2 to discontinued operations in the nine months ended
- 68 -
September 30, 2004, related to the sale of the Canadian oil and gas reserves.
Also contributing to the increase, although to a lesser extent, was additional
amortization related to tenant improvements and personnel costs.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Interest expense........................................................... $ 1,027.4 $ 791.2 $ (236.2) (29.9)%
Interest expense increased primarily as a result of higher average interest
rates and lower capitalization of interest expense. Our average interest rate
increased from 8.4% for the nine months ended September 30, 2004, to 9.7% for
the nine months ended September 30, 2005, primarily due to the impact of rising
U.S. interest rates and their effect on our existing variable rate debt
portfolio and higher average interest rates incurred on new debt instruments
that were entered into to replace and/or refinance existing debt instruments
during 2005. Interest capitalized decreased from $296.9 for the nine months
ended September 30, 2004, to $169.1 for the nine months ended September 30,
2005, as new plants entered commercial operations (at which point capitalization
of interest expense ceases) and because of suspended capitalization of interest
on three partially completed construction projects. We expect that the amount of
interest capitalized will continue to decrease in future periods as our plants
in construction are completed. During the nine months ended September 30, 2005,
(i) interest expense related to our Senior Notes, contingent convertible notes,
and term loans increased by $26.1; (ii) interest expense related to our CalGen
subsidiary increased $36.2; (iii) interest expense related to our
construction/project financing increased by $48.2; (iv) interest expense related
to our CCFC I subsidiary increased by $9.4; and (v) interest expense related to
preferred interests increased by $46.1 primarily due to the October 2004 closing
of the $360 offering of redeemable preferred securities by our indirect
subsidiary, Calpine Jersey I, and the $260 offering on January 31, 2005, of
redeemable preferred securities by our indirect subsidiary, Calpine Jersey II
(the Calpine Jersey I and Calpine Jersey II securities were repurchased with
proceeds from the sale of Saltend in July 2005). The $155 offering of redeemable
preferred securities by our indirect subsidiary, Metcalf, and the $150 offering
of redeemable preferred securities by our indirect subsidiary, CCFC LLC. These
increases in interest expense are partially offset by the decrease in interest
expense of $33.3 related to the convertible debentures payable to the Calpine
Capital Trusts, which have been redeemed.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Interest (income).......................................................... $ (57.4) $ (38.0) $ 19.4 51.1%
Interest (income) increased during the nine months ended September 30,
2005, due primarily to higher interest earned on margin deposits and collateral
posted to secure letters of credit and due to higher interest rates.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Minority interest expense.................................................. $ 31.8 $ 23.1 $ (8.7) (37.7)%
Minority interest expense increased during the nine months ended September
30, 2005, as compared to the same period in 2004 primarily due to an increase in
income at CPLP, which is 70% owned by CPIF. The variance is largely due to an
increase in availability at the Island Cogen plant in 2005 as a result of
non-recurrence of major maintenance work performed during 2004.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
(Income) from repurchase of debt........................................... $ (166.5) $ (170.5) $ (4.0) (2.3)%
- 69 -
The decrease in income from repurchase of debt is due to considerably
higher volumes (approximately $356.2) of Senior Notes repurchased during the
nine months ended September 30, 2004, versus 263.5in the same period in 2005.
The decrease was partially offset by higher discounts associated with
repurchases in the nine months ended September 30, 2005 compared to the same
period in 2004. See Note 7 of the Notes to Consolidated Condensed Financial
Statements for further information.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Other expense (income), net................................................ $ 71.4 $ (168.9) $ (240.3) (142.3)%
Other expense increased $240.3 for the nine months ended September 30,
2005, compared to a gain in the same period in 2004, primarily due to
non-recurring gains in the nine months ended September 30, 2004 of $171.5
related to the restructuring and sale of power purchase agreements for two of
our New Jersey plants, net of transaction costs and the write-off of unamortized
deferred financing costs. Also contributing to the unfavorable variance was an
impairment charge of $18.5 in 2005 related to our investment in Grays Ferry,
$11.4 of additional legal reserves provided for in 2005 compared to 2004, $8.4
of higher letter of credit fees in 2005 compared to 2004 and the write-off of
$5.9 of unamortized deferred financing costs in connection with the refinancing
of our Metcalf facility's project debt in 2005. Finally, during the nine months
ended September 30, 2005, non-cash foreign currency transaction losses were
higher than the same period in 2004 by $10.7. See the "foreign currency
transaction gain (loss)" discussion within "Financial Market Risks" for further
information.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Benefit for income taxes................................................... $ (167.9) $ (144.3) $ 23.6 16.4%
During the nine months ended September 30, 2005, our tax benefit increased
as compared to the nine months ended September 30, 2004 as our pre-tax loss
increased in 2005 by approximately $450.5. The effective tax rate decreased to
21.3% in 2005 compared to 42.6% in the same period in 2004. The favorable
variance of $23.6 was relatively moderate despite the significant increase in
our pre-tax loss largely due to a reserve recorded on certain deferred tax
assets associated with CCFC which had the effect of reducing the tax benefit on
tour pre-tax loss by approximately $143.4 million. The tax rates on continuing
operations for the nine months ended September 30, 2004, have been restated to
reflect the reclassification to discontinued operations of certain tax expense
related to the sale of oil and gas reserves, Saltend, and the Morris and
Ontelaunee power plants. See Note 8 of the Notes to Consolidated Condensed
Financial Statements for more information.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Discontinued operations, net of tax........................................ $ (62.4) $ 235.7 $ (298.1) (126.5)%
During the nine months ended September 30, 2005, discontinued operations
activity primarily consisted of the pre-tax gain on the sale of Saltend of $23.7
and the pre-tax gain on the sale of substantially all of our remaining oil and
gas assets of $340.2; both dispositions closed in July 2005. Offsetting these
gains are two pre-tax impairment charges of $106.2 and $136.8, related to the
sale of Morris and the pending sale of Ontelaunee, respectively; Ontelaunee met
the discontinued operations criterion as of September 30, 2005, under SFAS No.
144 and was written down to the estimated sales price, less transaction costs.
On a pre-tax basis, we recorded income from discontinued operations for the nine
months ended September 30, 2005 of $75.2. However, our effective tax rate on
discontinued operations for the three months ended September 30, 2005 was 183.0%
due primarily to a large tax return gain on the sale of Saltend and, as a
consequence, we recognized an after-tax loss from discontinued operations of
$62.4. Discontinued operations for the nine months ended September 30, 2004
consisted primarily of a pre-tax gain from the sale of our Canadian and U.S.
Rocky Mountain oil and gas assets of $203.5, and a pre-tax gain from the sale of
- 70 -
the Lost Pines I Power project of $35.3 as well as operating income from Lost
Pines I, Saltend and our Canadian and U.S. oil and gas operations. Operating
income from Saltend and the oil and gas assets were considerably higher for the
nine months ended September 30, 2004 compared to the same period in 2005
primarily due to the inclusion of the Canadian and U.S. Rocky Mountain income
within 2004 results and significant foreign currency transaction losses at
Saltend in 2005 related to a foreign currency exposure which did not exist
during the nine months ended September 30, 2004. On a net of tax basis, income
from discontinued operations for the nine months ended September 30, 2004 was
$235.7, based on an effective tax rate of 28.1%.
Nine Months Ended
September 30,
---------------------------
2005 2004 $ Change % Change
------------- ------------- ------------- -------------
Net income (loss).......................................................... $ (683.9) $ 41.2 $ (725.1) (1,760.0)%
For the nine months ended September 30, 2005, we reported revenue of $7.5
billion, representing an increase of 16.4% over the same period in the prior
year. Including the discontinued operations discussed below, we recorded a net
loss per share of $1.49, or a net loss of $683.9, compared to net income per
share of $0.10, or net income of $41.2, for the same period in the prior year.
For the nine months ended September 30, 2005, our average capacity in
operation for consolidated projects in continuing operations increased by 13.2%
to 25,079 megawatts. Generation volume was up 6.0% from the prior year as we
generated approximately 68.2 million megawatt-hours, which equated to a baseload
capacity factor of 45.9%, and realized an average spark spread of $22.16 per
megawatt-hour. For the same period in 2004, we generated 64.4 million
megawatt-hours, which equated to a baseload capacity factor of 50.1%, and
realized an average spark spread of $20.45 per megawatt-hour.
Gross profit increased by $92.8, or 30.1%, to $401.3 in the nine months
ended September 30, 2005, compared to the same period in the prior year, as
total spark spread increased by $196.1 period-to-period. However, spark spread
did not increase in line with the increases in plant operating expense, net
transmission purchase expense, depreciation, and interest expense.
During the nine months ended September 30, 2005, financial results were
positively impacted by $166.5 of income recorded from repurchase of debt
(compared to $170.5 in the same period of 2004) and negatively impacted by $34.4
in long-term service agreement cancellation charges. In addition, we recorded
$44.8 in project development expense due to the write-off of three projects in
suspended development and $12.3 in project development expense on preservation
costs for suspended projects. Interest expense increased $236.1 between periods
primarily due to an increase in the average interest rate and lower
capitalization of interest expense as fewer plants were in active construction.
Other expense was $71.4 for the nine months ended September 30, 2005,
compared to other income of $168.9 for the nine months ended September 30, 2004.
The net expense for the nine months ended September 30, 2005, was due mainly to
an impairment charge of $18.5 related to the sale of our interest in Grays Ferry
in July 2005, $18.3 of non-cash foreign currency transactions losses related to
inter-company transactions (versus $7.6 in the prior year), $16.6 in letter of
credit fees (versus $8.4 in the prior year) and higher legal reserves. Other
income for the nine months ended September 30, 2004, included approximately $171
in pre-tax gains from the restructuring and sale of power purchase agreements
for two of the company's New Jersey plants, net of transaction costs and the
write-off of unamortized deferred financing costs.
In the nine months ended September 30, 2005 we recorded a pre-tax gain from
discontinued operations of $75.2. However, our year-to-date effective tax rate
on discontinued operations was 183% due primarily to a large tax return gain on
the sale of Saltend and, as a consequence, we incurred an after-tax loss from
discontinued operations of $62.4. Discontinued operations included gains on the
sale of our remaining oil and gas assets and Saltend , both of which closed in
July 2005, and an impairment charge associated with the pending sale of
Ontelaunee , which was classified as held for sale at September 30, 2005 and
closed in October 2005. Discontinued operations also includes the operating
results until the respective sales dates for those entities and the Morris power
plant, for which we recorded an impairment charge in accordance with SFAS No.
144 in the second quarter of 2005, and which was sold in the third quarter of
2005. For the nine months ended September 30, 2004, we recorded a net gain in
discontinued operations of $235.7 from the sales of our Canadian and U. S. Rocky
Mountain oil and gas assets and the Lost Pines 1 Power Project.
- 71 -
Liquidity and Capital Resources
Our business is capital intensive. Our ability to capitalize on growth
opportunities and to service the debt we incurred in order to construct and
operate our current fleet of power plants is dependent on the continued
availability of capital. The availability of such capital in today's environment
remains uncertain. To date, we have obtained cash from our operations;
borrowings under credit facilities; issuances of debt, equity, preferred
securities and convertible and contingent convertible notes; proceeds from
sale/leaseback transactions; sale or partial sale of certain assets; prepayments
received for power sales; contract monetizations; and project financings. We
have utilized this cash to fund operations, service, repay or refinance debt
obligations, fund acquisitions, develop and construct power generation
facilities, finance capital expenditures, support hedging, balancing,
optimization and trading activities, and meet other cash and liquidity needs.
Consistent with our strategic initiative announced in May 2005, we expect
to rely to a greater extent than in the past on asset sales to reduce debt and
related interest expense and to improve our liquidity position.
Transactions completed in the three months ended September 30, 2005:
o Issued $150.0 million of Class A Redeemable Preferred Shares due 2006,
through our indirect subsidiary, CCFC LLC, which is an indirect parent
of CCFC I, which owns a portfolio of six operating natural gas-fired
power plants (not including Ontelaunee, which met the held for sale
criteria as of September 30, 2005) with the generation capacity of
more than 3,600 megawatts. The Redeemable Preferred Shares bear an
initial dividend rate of LIBOR plus 950 basis points and were
redeemable in whole or in part at any time by CCFC LLC at par plus
accrued dividends. The Redeemable Preferred Shares were repurchased in
full on October 14, 2005.
o Completed the sale of substantially all of our remaining domestic oil
and gas exploration and production properties and assets for $1.05
billion, less adjustments, transaction fees and expenses, and less
approximately $75 million to reflect the value of certain oil and gas
properties for which we were unable to obtain consents to assignment
prior to closing. Certain of the consents have been received
subsequent to September 30, 2005, and we expect to receive the
remaining consents by December 31, 2005. As further discussed in Note
12 of the Notes to Consolidated Condensed Financial Statements, the
Company initiated a lawsuit seeking access to blocked proceeds from
the sale.
o Completed the sale of Saltend, a 1,200-MW power plant in Hull,
England, generating total gross proceeds of $862.9 million. Of this
amount, approximately $647.1 million was used to redeem the $360.0
million Two-Year Redeemable Preferred Shares issued by our Calpine
Jersey I subsidiary on October 26, 2004, and the $260.0 million
Redeemable Preferred Shares issued by our Calpine Jersey II subsidiary
on January 31, 2005, including interest and termination fees of $16.3
million and $10.8 million, respectively. As described further in Note
12 of the Notes to Consolidated Condensed Financial Statements,
certain bondholders filed a lawsuit concerning the use of the proceeds
remaining from the sale of Saltend. As discussed in Note 12, certain
bondholders initiated a lawsuit concerning the use of the proceeds
remaining from the sale of Saltend.
o Completed the sale of our Inland Empire Energy Center development
project to GE, for approximately $30.9 million. The project will be
financed, owned and operated by GE and will be used to launch GE's
most advanced gas turbine technology, the "H System (TM)." The Company
will manage plant construction, market the plant's output, and manage
its fuel requirements. The Company has an option to purchase the
facility in years seven through fifteen following the commercial
operation date and GE can require the Company to purchase the facility
for a limited period of time in the fifteenth year, all subject to
satisfaction of various terms and conditions. If the Company purchases
the facility under the call or put, GE will continue to provide
critical plant maintenance services throughout the remaining estimated
useful life of the facility. Because of continuing involvement related
to the purchase option and put, the Company deferred the gain of
approximately $10 million until the call or put option is either
exercised or expires.
o Completed the sale of our 50% interest in the 175-MW Grays Ferry power
plant for gross proceeds of $37.4 million. We recorded an impairment
charge of $18.5 million related to our interest in the quarter ended
June 30, 2005.
o Completed the sale of our 156-MW Morris power plant for approximately
$84.5 million. In the three months ended June 30, 2005, we recorded a
$106.2 million impairment charge related to our commitment to a plan
- 72 -
of divesture of this facility, which was subsequently reclassified to
discontinued operations in the three months ended September 30, 2005,
upon completion of the sale.
o Repurchased approximately $138.9 million of our First Priority Notes
pursuant to a tender offer. Following the completion of the tender
offer, we now have approximately $641.5 million aggregate principal
amount of First Priority Notes outstanding.
o Announced a 15-year Master Products and Services Agreement with GE,
which is expected to lower operating costs in the future. As a result
of nine GE LTSA cancellations, we recorded $33.3 million in charges in
the quarter ended June 30, 2005.
o Signed an agreement with Siemens-Westinghouse to restructure the
long-term relationship, which we expect will provide us additional
flexibility to self-perform maintenance work in the future.
CalBear Transaction. On September 7, 2005, we and CES entered into a Master
Transaction Agreement with Bear Stearns pursuant to which we agreed to create a
new energy marketing and trading venture with Bear Stearns. At the closing of
the transactions contemplated by the Master Transaction Agreement, our indirect,
wholly owned subsidiary CMSC, and Bear Stearns' wholly owned subsidiary CalBear,
will also become parties. Pursuant to the terms of the Master Transaction
Agreement, upon closing, we and our affiliates, on the one hand, and Bear
Stearns and its affiliates, on the other hand, will each refer certain trades
and third party service transactions to CalBear. This referral obligation does
not include any transaction that could be serviced by, used by, hedge cash flow
from or otherwise optimize the results or flexibility of the assets of the
referring entity. Bear Stearns has agreed to provide CalBear with all funds and
collateral necessary for CalBear to perform its obligations under certain
agreements and to provide certain other financial support to CalBear.
The closing is subject to certain conditions, including the execution and
delivery of certain agreements, including an Agency and Services Agreement by
and among CMSC and CalBear, pursuant to which CMSC will act as CalBear's
exclusive agent for gas and power trading; a Trading Master Agreement by and
among CES, CMSC and CalBear, pursuant to which CalBear will execute credit
enhancement trades on behalf of CES; and an ISDA Master Agreement, Schedule, and
applicable annexes between CES and CalBear to effectuate the credit enhancement
trades. Pursuant to the Agency and Services Agreement, CSMC will earn service
fees (a portion of which will be held in reserve during the term of the Agency
and Services Agreement) equal to 50% of CalBear's profits, which fees (including
the reserve) are subject to a requirement to return based on losses at CalBear,
up to 50% of such losses. We received FERC approval on October 31, 2005.
The Master Transaction Agreement and the agreements entered into thereunder
will terminate on November 30, 2006 unless both we and Bear Stearns affirm the
continuation of the Master Transaction Agreement upon 90 days' advance notice to
the other, and will terminate at the end of each calendar quarter thereafter
unless extended by both parties. In addition, both we and Bear Stearns may
terminate the Master Transaction Agreement voluntarily upon 90 days' advance
written notice and for specified causes. In addition, none of the parties will
enter into a venture that substantially replicates the transactions contemplated
by the Master Transaction Agreement during its term and for a period of up to
two years after its termination, depending upon the reason for the termination.
Transactions completed subsequent to September 30, 2005 (See Note 15 of the
Notes to Consolidated Condensed Financial Statements for more information):
o Completed the sale of our 561-MW Ontelaunee power plant for $225.0
million, less transaction costs and working capital adjustments of
approximately $13.0 million. The Company recorded an impairment charge
of $136.8 million as of September 30, 2005, is reflected in
discontinued operations. The sale of Ontelaunee closed October 6,
2005. See Notes 5 and 8 of the Notes to Consolidated Condensed
Financial Statements for more information. CCFC I made offers to
purchase its outstanding debt with the proceeds of the Ontelaunee sale
in accordance with the instruments governing such debt. The offers
have expired, and none of the holders of such debt elected to have
their debt repurchased.
o Received funding for CCFC LLC's $300.0 million offering of 6-year
Redeemable Preferred Shares 2011.
o Repurchased the CCFC LLC $150.0 million Class A Redeemable Preferred
Shares due 2006.
While we have recognized a pre-tax gain overall on asset sales completed
during the three and nine months ended September 30, 2005, we have recognized
significant impairment charges or losses with respect to certain asset sales,
including the sale of the Morris facility, as well as the sale of the Ontelaunee
facility in October 2005. We are considering the sale of additional assets in
- 73 -
connection with our strategic initiative program, and it is possible that some
or all of the additional asset sales contemplated could lead to material
impairment charges or losses upon sale.
As a result of transactions subsequent to March 31, 2005, we have lowered
our total debt at September 30, 2005, by approximately $0.9 billion to $17.2
billion. Excluding the effect of new construction financing of $178.7 million,
the Company has reduced debt by approximately $1.1 billion in this six month
period.
Debt repurchases and redemptions during the three months ended September 30,
2005:
During the three months ended September 30, 2005, we repurchased Senior
Notes in open market transactions totaling $263.5 million in principal amount.
For cash of $233.9 million plus accrued interest, we repurchased the Senior
Notes as follows (in thousands):
Senior Notes Principal Cash Payment
- ------------ ----------------- ---------------
8 1/4% due 2005................................................................................. 4,000.0 3,985.0
10 1/2 % due 2006............................................................................... 10,005.0 9,671.0
7 5/8% due 2006................................................................................. 8,051.0 7,648.4
8 3/4% due 2007................................................................................. 2,000.0 1,570.0
7 7/8% due 2008................................................................................. $ 53,500.0 $ 39,598.8
8 1/2% due 2008................................................................................. 41,000.0 3,900.0
7 3/4% due 2009................................................................................. 6,000.0 28,632.5
9 5/8% due 2014................................................................................. 138,895.0 138,895.0
---------------- ----------------
Total repurchases............................................................................ $ 263,451.0 $ 233,900.7
================ ================
For the three months ended September 30, 2005, we recorded an aggregate
pre-tax gain of $23.6 million on the above repurchases after the write-off of
unamortized deferred financing costs, legal fees, and unamortized discounts. In
addition, we redeemed and extinguished HIGH TIDES III for a pre-tax loss of $8.0
million after the write-off of unamortized deferred financing costs, legal fees
and unamortized discounts.
The sale of assets to reduce debt and lower annual interest costs is
expected to materially lower our revenues, spark spread and gross profit (loss)
in the near term and possibly longer. The final mix of assets actually sold will
determine the degree of impact on operating results. While lowering debt, the
accomplishment of the strategic initiative program, in and of itself, will
likely not lead to improvement in certain measures of interest and principal
coverage without significant improvement in market conditions. The amount of
offsetting future interest savings will be a function of the principal amount of
debt retired, and the interest rate born by such debt, and the amount that we
will spend to reduce debt will depend on the market price of such debt and other
factors. The final net future earnings impact of the initiatives is still
uncertain. Our ability to use the proceeds from asset sales is generally subject
to restrictions in our indentures (see Note 7 to the Consolidated Condensed
Financial Statements). Further, as discussed above and in Note 12 of the Notes
to Consolidated Condensed Financial Statements, we have experienced certain
legal challenges to our intended use of proceeds from certain asset sales, and
such challenges could affect the timing or ultimate use of such proceeds.
Capital Availability -- While we have been able to access the capital and
bank credit markets since 2002, it has been on significantly different terms
than before 2002. In particular, our senior working capital facilities and term
loan financings entered into, and the majority of our debt securities offered
and sold by us have been secured by certain of our assets and subsidiary equity
interests. We have also provided security to support our prepaid commodity
transactions and, as our credit ratings have been downgraded, we have been
required to post cash collateral to support our hedging, balancing and
optimization activities. In the aggregate, the average interest rate on our new
debt instruments, especially on recent issuances of subsidiary preferred stock
and or debt incurred to refinance existing debt, has been higher. The terms of
capital available to us now and in the future may not be attractive to us or our
access to capital markets may otherwise become restricted. 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. In
addition, we are currently involved in various litigations with the holders of
certain series of our outstanding secured and unsecured bonds as described in
Note 12 of the Notes to Consolidated Condensed Financial Statements. The outcome
of these litigations is uncertain, and if, as a result of these litigations, the
Company's access to the proceeds of asset sales continues to be restricted, or
the Company is required to restore proceeds of asset sales that have previously
been utilized by the Company, it could have a material adverse effect on the
Company and its liquidity.
- 74 -
Satisfying the obligations under our outstanding indebtedness, and funding
anticipated capital expenditures and working capital requirements for the next
twelve months and potentially thereafter, presents us with several challenges as
our cash requirements are expected to exceed the sum of our cash on hand
permitted to be used to satisfy such requirements and cash from operations.
Accordingly, we have in place a strategic initiative, discussed above, which
includes several components including possible sales or monetizations of certain
of our assets. Whether we will have sufficient liquidity will depend, in part,
on the success of that program. No assurance can be given that it will be
successful. If it is not successful, additional asset sales, refinancings,
monetizations and other actions beyond those included in the strategic
initiative would likely need to be made or taken, depending on market
conditions. Our ability to reduce debt will also depend on our ability to
repurchase debt securities through open market and other transactions, and the
principal amount of debt we are able to repurchase will be contingent upon
market prices and other factors, including the ultimate outcome of disputes
related to our intended use of the proceeds of certain asset sales (see Note 12
of the Notes to Consolidated Condensed Financial Statements for more
information). Even if our strategic initiative program is successful, there can
be no assurance that we will be able to continue work on our projects in
development and suspended construction that have not been successfully project
financed, and we could possibly incur substantial impairment losses as a result.
Even if the strategic initiative is successful, until there are significant
sustained improvements in spark spreads, we expect that we will not have
sufficient cash flow from operations to repay all of our indebtedness at
maturity or to fund our other liquidity needs. We expect that we will need to
extend or refinance all or a portion of our indebtedness on or before maturity.
While we currently believe that we will be successful in repaying, extending or
refinancing all of our indebtedness on or before maturity, we cannot assure you
that we will be able to do so on attractive terms, or at all. For further
discussion of this see the risk factors in our 2004 Form 10-K and our Current
Report on Form 8-K filed with the SEC on July 1, 2005.
Cash Flow Activities -- The following table summarizes our cash flow
activities for the periods indicated:
Nine Months Ended
September 30,
----------------------------------
2005 2004
-------------- --------------
(In thousands)
Beginning cash and cash equivalents............................................................ $ 718,023 $ 954,827
Net cash provided by (used in):
Operating activities......................................................................... (407,973) 229,870
Investing activities......................................................................... 822,689 (381,934)
Financing activities......................................................................... (308,971) 633,703
Effect of exchange rates changes on cash and cash equivalents................................ 741 14,377
Change in discontinued operations cash classified as current assets held for sale............ 18,627 7,694
-------------- --------------
Net increase in cash and cash equivalents.................................................... 125,113 503,710
-------------- --------------
Ending cash and cash equivalents............................................................... $ 843,136 $ 1,458,537
============== ==============
Operating activities for the nine months ended September 30, 2005, used net
cash of $408.0 million, as compared to providing $229.9 million for the same
period in 2004. In the first nine months of 2005 there was a $205.2 million use
of funds from net changes in operating assets and liabilities comprised of an
increase in accounts receivable of $416.5 million and an increase in net margin
deposits posted to support CES contracting activity of $24.1 million. This was
offset by an increase in accounts payable of $212.1 million and a decrease in
inventory of $20.0 million. The significant increase in accounts receivable
period over period was primarily due to the significant increase in power prices
during the three-month period ended September 30, 2005, and to a lesser extent,
an increase in megawatt hours sold (due to additional generation capacity) from
September 30, 2004 to September 30, 2005.
In the first nine months of 2004, operating cash flows 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. We had an $11.3 million use of funds from net
changes in operating assets and liabilities, including an increase of $104.8
million in accounts receivable, partially offset by an increase of $218.9
million in accounts payable and a $14.1 million decrease in net margin deposits
posted to support CES contracting activity.
Investing activities for the nine months ended September 30, 2005, provided
net cash of $822.7 million, as compared to using $381.9 million in the same
period of 2004. Capital expenditures, including capitalized interest, for the
completion of our power facilities decreased from $1,184.4 million in 2004 to
- 75 -
$675.7 million in 2005 as there were fewer projects under construction.
Investing activities in 2005 reflected the receipt of $897.6 million from the
sale of our oil and natural gas assets, $843.1 million from the sale of our
Saltend power plant in the UK, $84.5 million from the sale of our Morris
facility, $30.4 million from the sale of our Inland Empire development project
and $36.9 million from the sale of our investment in the Grays Ferry power
plant. Additionally, investing activities in 2005 reflect the receipt of $132.5
million from the disposition of our investment in High Tides III, offset by a
$559.9 million increase in restricted cash, including $401.7 million from the
proceeds of the sale of our oil and gas assets, which is the subject of a
lawsuit. See Note 12 in the Notes to Consolidated Condensed Financial Statements
for more information regarding this matter. 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 U.S. 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, offset by the
purchase of the Brazos Valley power plant, the remaining 50% interest in the
Aries power plant, and the remaining 20% interest in Calpine Cogen. Also, we
used $111.6 million to purchase a portion of High Tides III and invested $124.2
million in restricted cash during the nine month period of 2004
Financing activities for the nine months ended September 30, 2005, used
$309.0 million, as compared to providing $633.7 million in 2004. We continued
our refinancing program in the first nine months of 2005 by raising $260.0,
$155.0 and $150.0 million (which was repurchased on October 14, 2005) from
preferred securities offerings by Calpine Jersey II, Metcalf and CCFC LLC,
respectively, $650.0 million from the 2015 Convertible Notes offering, $621.0
million from various project financings and $290.6 million from a prepaid
commodity derivative contract at our Deer Park facility. We continued our debt
reduction program by using $353.3 million to repay notes payable and project
financing debt, $628.5 million to repay preferred security offerings (including
the Calpine Jersey II mentioned above) in addition to using $821.3 million to
repay or repurchase Senior Notes and $517.5 million to repay High Tides III.
Additionally, we incurred $89.3 million in financing and transaction costs.
Working Capital -- At September 30, 2005, we had working capital of $520.8
million which increased approximately $242.7 million from December 31, 2004. The
increase was primarily due to increases of $494.6 million, $513.4 million, and
$379.5 million in accounts receivable, restricted cash, and current derivative
assets, respectively, offset by increases of $212.1 million, $249.4 million and
$618.1 million in accounts payable, Senior Notes, current portion and current
derivative liabilities, respectively, from December 31, 2004, to September 30,
2005. The increase in accounts receivable period over the period was primarily
due to the significant increase in power prices during the three-month period
ended September 30, 2005, and to a lesser extent, an increase in megawatt hours
sold (due to additional generating capacity). Restricted cash increased
primarily due to the addition of $607.5 in remaining net proceeds from the sale
of Saltend and our remaining oil and gas assets in July 2005. Our current
derivative assets and liabilities increased significantly primarily as a result
of significantly higher electricity and natural gas prices at the end of the
third quarter in 2005. Cash flow used in operating activities during the
nine-month period ended September 30, 2005, was $408.0 million and is expected
to continue to be negative at least for the near term and possibly longer. On
September 30, 2005, our cash and cash equivalents on hand totaled $843.1
million. The current portion of restricted cash totaled $1,106.7 million. See
Note 2 for more information on our cash and cash equivalents and restricted
cash.
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 have below
investment grade credit ratings and certain have sought bankruptcy protection or
reorganization. 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, 2005 and December 31, 2004,
we had approximately $592.1 million and $596.1 million, respectively, in letters
of credit outstanding under various credit facilities to support our risk
management and other operational and construction activities. Of the total
letters of credit outstanding, $194.4 million and $233.3 million, respectively,
were issued under the cash collateralized letter of credit facility at September
30, 2005 and December 31, 2004, respectively.
Commodity Margin Deposits and Other Credit Support -- As of September 30,
2005 and December 31, 2004, to support commodity transactions we had deposited
net amounts of $273.0 million and $248.9 million, respectively, in cash as
margin deposits with third parties, and we made gas and power prepayments of
$78.9 million, and $78.0 million, respectively, and had letters of credit
outstanding of $181.1 million and $115.9 million, respectively. Since December
31, 2004, such amounts have increased as commodity prices have risen. We use
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margin deposits, prepayments and letters of credit as credit support for
commodity procurement and risk management activities. Future cash collateral
requirements may increase or decrease based on the extent of our involvement in
standard contracts and movements in commodity prices and also based on our
credit ratings and general perception of creditworthiness in the market.
Unrestricted Subsidiaries -- The information in this paragraph is required
to be provided under the terms of 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." We
have 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, 2005, and selected income
statement information for the nine months ended September 30, 2005 (in
thousands):
Calpine
Corporation
and Restricted Unrestricted
Subsidiaries Subsidiaries Eliminations Total
--------------- --------------- --------------- ----------------
Assets...................................................... $ 26,888,675 $ 429,183 $ (229,621) $ 27,088,237
=============== =============== =============== ===============
Liabilities................................................. $ 22,708,923 $ 246,149 $ -- $ 22,955,072
=============== =============== ================ ===============
Total revenue............................................... $ 7,522,915 $ 9,781 $ (6,468) $ 7,526,228
Total cost of revenue....................................... (7,117,986) (16,305) 9,388 (7,124,903)
Interest income............................................. 49,947 12,706 (5,236) 57,417
Interest expense............................................ (1,017,659) (9,723) -- (1,027,382)
Other....................................................... (116,371) 1,132 -- (115,239)
--------------- --------------- ---------------- ---------------
Net income................................................ $ (679,154) $ (2,409) $ (2,316) $ (683,879)
=============== =============== =============== ===============
Bankruptcy-Remote Subsidiaries -- Pursuant to applicable transaction
agreements, we have established certain of our entities separate from Calpine
and its other subsidiaries. At September 30, 2005 these entities included: CCFC
LLC, Metcalf LLC, Rocky Mountain Energy Center, LLC, Riverside Energy Center,
LLC, Calpine Riverside Holdings, LLC, Calpine Energy Management, L.P., CES GP,
LLC, PCF, PCF III, CNEM, 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.), Calpine Deer Park Partner, LLC,
Calpine DP, LLC and Deer Park.
Indenture and Debt and Lease Covenant Compliance -- Certain of our
indentures place conditions on our ability to issue indebtedness if our interest
coverage ratio (as defined in those indentures) is below 2:1. Currently, our
interest coverage ratio (as so defined) is below 2:1 and, consequently, we
generally would not be allowed 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 ability to invest in
unrestricted subsidiaries and non-subsidiary affiliates and make certain other
types of restricted payments will be limited. Moreover, certain of our
indentures will prohibit any further investments in non-subsidiary affiliates if
and for so long as our interest coverage ratio (as defined therein) is below
1.75:1 and, as of September 30, 2005, such interest coverage ratio was below
1.75:1. We currently do not expect this limitation on our ability to make
investments in non-subsidiary affiliates to have a material impact on our
business.
Certain of the Company's indebtedness issued in the last half of 2004 was
incurred in reliance on provisions in certain of its existing indentures
pursuant to which the Company is able to incur indebtedness if, after giving
effect to the incurrence and the repayment of other indebtedness with the
proceeds there from, the Company's interest coverage ratio (as defined in those
indentures) is greater than 2:1. In order to satisfy the interest coverage ratio
requirement in connection with such issuances, the proceeds thereof was required
to be used to repurchase or redeem other existing indebtedness. As previously
reported in the Company's 2004 10-K and its Quarterly Reports on Form 10-Q for
the first two quarters of 2005, the Company completed a substantial portion of
such repurchases during the fourth quarter of 2004 and the first six months of
2005. The Company completed the required repurchases, spending approximately
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$248.4 million in the third quarter of 2005 to repurchase debt, and has now
fully satisfied this requirement. The amount we were required to spend exceeded
our estimate of $184.0 million because the required principal amount of debt was
repurchased at prices higher than originally anticipated.
When the Company or one of its subsidiaries sells a significant asset or
issues preferred equity, the Company's indentures generally require that the net
proceeds of the transaction be used to make capital expenditures, to acquire
permitted assets or capital stock, or to repurchase or repay indebtedness, in
each case within 365 days of the closing date of the transaction. To the extent
that $50 million or more of such net proceeds are not so used, the Company is
required under the terms of its secured debt instruments to make an offer to
purchase its outstanding senior secured indebtedness up to the amount of the
unused net proceeds. This general requirement contains certain customary
exceptions, and, in the case of certain assets defined as "designated assets"
under some of the Company's indentures, including the gas portion of the
Company's oil and gas assets sold in July 2005, there are additional provisions
discussed further below that apply to the use of the proceeds of a sale of those
assets. In light of these requirements, and after taking into account the amount
of capital expenditures currently budgeted for the remainder of 2005 and
forecasted for 2006, the Company anticipates that, in the fourth quarter of 2005
and the first three quarters of 2006, it will need to use approximately $195.5
million and $668.5 million, respectively, of the net proceeds from four series
of preferred equity issued by subsidiaries of the Company and three asset sale
transactions, all completed prior to September 30, 2005, to repurchase or repay
indebtedness or acquire assets or capital stock. The Company has, subsequent to
September 30, 2005, fulfilled the portion of this obligation as required to be
completed in the fourth quarter of 2005. Accordingly, assuming that the Company
would fulfill the remaining obligations by repurchasing indebtedness, an
aggregate amount of approximately $714.0 million of Senior notes and terms
loans, net of current portion, and $150.0 million of Preferred interest, net of
current portion, related to this use of remaining net proceeds requirement has
been classified as Senior Notes, current portion, and Preferred interest,
current portion, respectively, on the Company's Consolidated Condensed Balance
Sheet as of September 30, 2005. The actual amount of the net proceeds that will
be required to be used to repurchase or repay debt will depend, among other
things, upon the actual amount of the net proceeds that is used to make capital
expenditures or acquire other assets or capital stock, which may be more or less
than the amount currently budgeted and/or forecasted. This amount includes
$207.5 million of the net proceeds of the sale of Saltend. As described further
in Note 12 of the Notes to Consolidated Condensed Financial Statements, certain
bondholders filed a lawsuit concerning the use of the proceeds from the sale of
Saltend. In connection with that lawsuit, the Company is prohibited from
repatriating this amount due to an order of the Court in that matter requiring
such proceeds to be held at or in the control of CCRC. To the extent
repatriation of such net proceeds is ultimately permitted, the repatriated net
proceeds will be applied pursuant to the use of proceeds provisions of the
Company's indentures described herein as if the sale of Saltend had occurred on
the date of repatriation.
In addition, the net proceeds from an issuance of preferred equity and an
asset sale completed after September 30, 2005 will similarly be subject to such
use of proceeds provisions of the Company's indentures, and the Company
anticipates that, on the basis described above (after considering capital
expenditures), an additional $452.1 million will need to be used to make capital
expenditures, to acquire other assets or capital stock, or to repurchase
indebtedness, as applicable, within 365 days of the consummation of the
applicable transaction.
As noted above, our remaining oil and gas assets were sold on July 7, 2005,
with the gas component of such sale constituting "designated assets" under
certain of our indentures. These indentures require us to make an offer to
purchase our First Priority Notes with the net proceeds of a sale of designated
assets not otherwise applied in accordance with the other permitted uses under
such indentures and, to the extent any proceeds (above $50.0 million remain
thereafter, to make an offer to purchase its second priority senior secured
debt. Accordingly, we made an offer to purchase the First Priority Notes in June
2005. On July 12, 2005, we purchased, with proceeds of the sale of the gas
assets, all of the approximately $138.9 million in principal amount of the First
Priority Notes tendered in connection with the offer to purchase. Having
completed the tender offer, we have used approximately $308.2 million of the
$708.5 million of the remaining net proceeds arising from the sale of our gas
assets to acquire natural gas and/or geothermal energy assets permitted to be
acquired under such indentures. However, there can be no assurance that we would
be successful in identifying or acquiring any additional such assets on
acceptable terms or at all. If we do not, within 180 days of receipt of the net
proceeds from the sale of our gas assets, use all of the remaining net proceeds
to acquire such such assets, and/or to repurchase or repay (through open market
or privately-negotiated transactions, tender offers or otherwise) any or all of
the approximately $641.5 million aggregate principal amount of First Priority
Notes remaining outstanding after consummation of the offer to purchase
described above (either of which actions we may, but are not required, to take),
then we will, to the extent that the remaining net proceeds from the sale exceed
$50 million, be required under the terms of our Second Priority Secured Debt
- 78 -
instruments to make an offer to purchase our outstanding second priority senior
secured indebtedness, of which $3.7 billion is outstanding, up to the amount of
the remaining net proceeds. However, as described further in Note 12, on
September 26, 2005, the Company filed a lawsuit seeking acces to blocked
proceeds remaing from this sale of designated assets. If the Company does not
ultimately prevail in this lawsuit, particularly if the Company is compelled to
return previously withdrawn amounts to the gas sale proceeds account as more
fully described in Note 12 of the Notes to Consolidated Condensed Financial
Statements, it could have a material adverse effect on the Company and its
liquidity.
In connection with several of our subsidiaries' lease financing
transactions (Agnews, Geysers, Pasadena, Broad River, RockGen and South Point)
the insurance policies we have in place do not comply in every respect with the
insurance requirements set forth in the financing documents. We have requested
from the relevant financing parties, and are expecting to receive, waivers of
this noncompliance. While failure to have the required insurance in place is
listed in the financing documents as an event of default, the financing parties
may not unreasonably withhold their approval of our waiver request so long as
the required insurance coverage is not reasonably available or commercially
feasible and we deliver a report from our insurance consultant to that effect.
We have delivered the required insurance consultant reports to the relevant
financing parties and therefore anticipate that the necessary waivers will be
executed shortly.
In connection with the sale/leaseback transaction of Agnews, we have not
fully complied with covenants pertaining to the operations and maintenance
agreement, which noncompliance is technically an event of default. We are in the
process of addressing this by seeking the lessor's approval to renew and extend
the operations and maintenance agreement for the Agnews facility.
In connection with the sale/leaseback transaction of Calpine Monterey
Cogeneration, Inc., we have not fully complied with covenants pertaining to
amendments to gas and power purchase agreements and the requirements to provide
a detailed accounting report, which noncompliance is technically an event of
default. We are in the process of addressing this by seeking a consent and
waiver.
Almost all of our operations are conducted through our subsidiaries and
other affiliates. As a result, we depend almost entirely upon their cash flow to
service our indebtedness, including our ability to pay the interest on and
principal of our Senior Notes. However, as also described in our 2004 Form 10-K,
first quarter 10-Q, second quarter 10-Q, and Current Report on Form 8-K filed
with the SEC on July 1, 2005, and Current Report on Form 8-K filed with the SEC
on October 17, 2005, cash flow from operations is currently insufficient to meet
in full our cash, liquidity and refinancing obligations for the year, so we
presently also depend in part upon the success of our strategic initiative
program in order to fully service our debt. In addition, financing agreements
covering a substantial portion of the indebtedness of our subsidiaries and other
affiliates restrict their ability to pay dividends, make distributions or
otherwise transfer funds to us prior to the payment of their obligations,
including their outstanding debt, operating expenses, lease payments and
reserves.
Effective Tax Rate -- For the three months ended September 30, 2005, the
effective rate from continuing operations increased to (7.8)% as compared to
(237.6)% for the three months ended September 30, 2004. For the nine months
ended September 30, 2005, and 2004, the effective tax rate was 21.3% and 42.6%,
respectively. The tax rates on continuing operations for the three and nine
months ended September 30, 2005, were adversely affected due to a valuation
allowance recorded against certain NOL deferred tax assets associated with CCFC
LLC in the amount of approximately $143.4 million. The variance in the effective
tax rate for the three months ended September 30, 2005 compared to the same
period in 2004 was significantly impacted by the nominal absolute dollar amount
of our pre-tax income (loss) in each period. For the three months ended
September 30, 2004, our pre-tax income from continuing operations was $8.6
million. Therefore, due to the near break-even absolute value of this amount,
the tax benefit for the period translated into a high tax rate percentage, even
though the benefit was only $20.3 million. Conversely, for the three months
ended September 30, 2005, our pre-tax loss from continuing operations was $224.9
million and the tax provision for the period was $17.5 million. Excluding the
effects of the valuation allowance associated with CCFC LLC, we would have
recognized a tax benefit of $125.9 million for the three months ended September
30, 2005 resulting in an effective tax rate of 56.0%. While this tax benefit
(excluding the effects of CCFC LLC) was $105.6 million higher than the tax
benefit recognized for the three months ended September 30, 2004, the effective
tax rate was significantly higher for the three months ended September 30, 2004
due to the nominal absolute value of pre-tax income from continuing operations.
Also, the tax rates on continuing operations for the three and nine months ended
September 30, 2004, have been restated in accordance with FIN 18, "Accounting
for Income Taxes in Interim Periods - an Interpretation of APB Opinion No. 28,"
as amended, to reflect the effects of classifying the sale of the Company's
Canadian and U.S. Rocky Mountain oil and gas assets, and the Saltend, Morris and
Ontelaunee power plants. See Note 8 of the Notes to Consolidated Condensed
- 79 -
Financial Statements for more information on discontinued operations. This
effective tax rate on continuing operations is based on the consideration of
estimated year-end earnings in estimating the quarterly effective rate, the
effect of permanent non-taxable items and establishment of valuation allowances
on certain deferred tax assets.
Off-Balance Sheet Commitments -- In accordance with SFAS No. 13 and SFAS
No. 98, "Accounting for Leases" our facility operating leases, which include
certain sale/leaseback transactions, are not reflected on our balance sheet. All
lessors in these contracts are third parties that are unrelated to us. The
sale/leaseback transactions utilize SPEs formed by the equity investors with the
sole purpose of owning a power generation facility. Some of our operating leases
contain customary restrictions on dividends, additional debt and further
encumbrances similar to those typically found in project finance debt
instruments. We have no ownership or other interest in any of these SPEs.
Effective Tax Rate -- For the three months ended September 30, 2005, the
effective rate from continuing operations increased to (7.8)% as compared to
(237.6)% for the three months ended September 30, 2004. For the nine months
ended September 30, 2005, and 2004, the effective tax rate was 21.3% and 42.6%,
respectively. The tax rates on continuing operations for the three and nine
months ended September 30, 2005, were adversely affected due to a valuation
allowance recorded against certain NOL deferred tax assets associated with CCFC
LLC in the amount of approximately $143.4 million. The variance in the effective
tax rate for the three months ended September 30, 2005 compared to the same
period in 2004 was significantly impacted by the nominal absolute dollar amount
of our pre-tax income (loss) in each period. For the three months ended
September 30, 2004, our pre-tax income from continuing operations was $8.6
million. Therefore, due to the near break-even absolute value of this amount,
the tax benefit for the period translated into a high tax rate percentage, even
though the benefit was only $20.3 million. Conversely, for the three months
ended September 30, 2005, pre-tax loss from continuing operations was $224.9
million and the tax provision for the period was only $17.5 million. Excluding
the effects of the valuation allowance associated with CCFC LLC, we would have
recognized a tax benefit of $125.9 million for the three months ended September
30, 2005 resulting in an effective tax rate of 56.0%. While this tax benefit
(excluding the effects of CCFC LLC) was $105.6 million higher than the tax
benefit recognized for the three months ended September 30, 2004, the effective
tax rate was significantly higher for the three months ended September 30, 2004
due to the nominal absolute value of pre-tax income from continuing operations.
Also, the tax rates on continuing operations for the three and nine months ended
September 30, 2004, have been restated in accordance with FIN 18, "Accounting
for Income Taxes in Interim Periods - an Interpretation of APB Opinion No. 28,"
as amended, to reflect the effects of classifying the sale of the Company's
Canadian and U.S. Rocky Mountain oil and gas assets, and the Saltend, Morris and
Ontelaunee power plants as discontinued operations due to our commitment to a
plan of divesture in the second quarter of 2005. See Note 8 for more
information. This effective tax rate on continuing operations is based on the
consideration of estimated year-end earnings in estimating the quarterly
effective rate, the effect of permanent non-taxable items and establishment of
valuation allowances on certain deferred tax assets.
We own a 32.3% interest in AELLC. AELLC owns the 136-MW Androscoggin Energy
Center located in Maine. On November 3, 2004, a jury verdict was rendered
against AELLC in a breach of contract dispute with IP. See Note 12 of the Notes
to Consolidated Condensed Financial Statements for more information about this
legal proceeding. We recorded our $11.6 million share of the award amount in the
third quarter of 2004. On November 26, 2004, AELLC filed a voluntary petition
for relief under Chapter 11 of the U.S. Bankruptcy Code. As a result of the
bankruptcy, we lost significant influence and control of the project and have
adopted the cost method of accounting for our investment in AELLC. Also, in
December 2004, we determined that our investment in AELLC was impaired and
recorded a $5.0 million impairment reserve. On April 12, 2005, AELLC sold three
fixed-price gas contracts to Merrill Lynch Commodities Canada, ULC, and used a
portion of the proceeds to pay down its remaining construction debt. As of
September 30, 2005, the facility had third-party debt outstanding of $3.1
million. See Note 12 of the Notes to Consolidated Condensed Financial Statements
for an update on this investment.
Credit Considerations -- On May 9, 2005, Standard & Poor's lowered its
corporate credit rating on Calpine Corporation to B- from B. The outlook remains
negative. In addition, the ratings on Calpine's debt and the ratings on the debt
of its subsidiaries were also lowered by one notch, with a few exceptions.
On May 12, 2005, Moody's Investor Service lowered its senior implied issuer
rating on Calpine Corporation to B3 from B2. The outlook remains negative. In
addition, the ratings on Calpine's debt and the ratings on the debt of its
subsidiaries were also lowered by two notches, with a few exceptions.
On November 4, 2005, following the announcement of our third quarter 2005
results of operation release on November 3, 2005, Fitch Ratings downgraded its
ratings on our senior unsecured notes to CCC- from CCC+. Calpine Canada Energy
Finance ULC bonds were also downgraded to CCC- from CCC+ (all with negative
outlook). Our second priority notes were downgraded to B from BB-, while first
priority notes were reduced to B- from B+. This downgrade is not expected to
materially impact our operations.
Credit rating downgrades have had a negative impact on our liquidity by
reducing attractive financing opportunities and increasing the amount of
collateral required by trading counterparties. Any future credit rating
downgrades could have similar effects on our liquidity.
Capital Spending -- See Note 5 of the Notes to Consolidated Condensed
Financial Statements for a discussion of our development and construction
projects at September 30, 2005
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Performance Metrics
In understanding our business, we believe that certain non-GAAP operating
performance metrics are particularly important. These are described below:
o Total deliveries of power. We both generate power that we sell to
third parties and purchase power for sale to third parties in HBO
transactions. The former sales are recorded as electricity and steam
revenue and the latter sales are recorded as sales of purchased power
for hedging and optimization. The volumes in MWh for each are key
indicators of our respective levels of generation and HBO activity and
the sum of the two, our total deliveries of power, is relevant because
there are occasions where we can either generate or purchase power to
fulfill contractual sales commitments. Prospectively, beginning
October 1, 2003, in accordance with EITF 03-11, "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,' 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.
o 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.
o Average heat rate for gas-fired fleet of power plants expressed in 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.
o 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, the spread on sales of
purchased power for hedging, balancing, and optimization activity and
generating revenue recorded in mark-to-market activities, net, by (b)
total generated MWh in the period.
o 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 gas pipeline charges, which is eliminated in
consolidation), the spread on sales of purchased gas for hedging,
balancing, and optimization activity and fuel expense related to
generation recorded in mark-to-market activities, net by (b) the heat
content in millions of Btu's of the fuel we consumed in our power
plants for the period.
o 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.
- 81 -
o Average plant operating expense per normalized MWh. To assess trends
in electric power 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,
-------------------------------- -------------------------------
2005 2004 2005 2004
------------- ------------- ------------- --------------
(In thousands)
Operating Performance Metrics:
Total deliveries of power:
MWh generated.................................................. 28,709 26,604 68,240 64,357
HBO and trading MWh sold....................................... 11,643 13,395 36,072 39,157
------------- ------------- ------------- -------------
MWh delivered.................................................. 40,352 39,999 104,312 103,514
============= ============= ============= =============
Average availability............................................. 97% 98% 92% 93%
Average baseload capacity factor:
Average total consolidated gross MW in operation............... 26,126 24,230 25,079 22,146
Less: Average MW of pure peakers............................... 2,965 2,951 2,965 2,951
------------- ------------- ------------- -------------
Average baseload MW in operation............................... 23,161 21,279 22,114 19,195
Hours in the period............................................ 2,208 2,208 6,552 6,576
Potential baseload generation.................................. 51,139 46,984 144,891 126,226
Actual total generation........................................ 28,709 26,604 68,240 64,357
Less: Actual pure peakers' generation.......................... 1,069 557 1,668 1,130
------------- ------------- ------------- -------------
Actual baseload generation..................................... 27,640 26,047 66,572 63,227
Average baseload capacity factor............................... 54.0% 55.4% 45.9% 50.1%
Average heat rate for gas-fired power plants (excluding peakers)
(Btu's/KWh):
Not steam adjusted............................................. 8,050 8,276 8,346 8,292
Steam adjusted................................................. 7,171 7,178 7,202 7,208
Average all-in realized electric price:
Electricity and steam revenue.................................. $ 2,096,323 $ 1,544,329 $ 4,625,078 $ 3,851,914
Spread on sales of purchased power for hedging and optimization 69,503 79,355 233,427 135,912
------------- ------------- ------------- -------------
Electricity and steam revenue before mark-to-market
activities, net (in thousands)................................ $ 2,165,826 $ 1,623,684 $ 4,858,505 $ 3,987,826
Electricity and steam revenue related to power generating
in mark-to-market activities, net............................. 82,583 -- 157,096 --
------------- -------------- ------------- --------------
Adjusted electricity and steam revenue (in thousands).......... $ 2,248,409 $ 1,623,684 $ 5,015,601 $ 3,987,826
MWh generated (in thousands)................................... 28,709 26,604 68,240 64,357
Average all-in realized electric price per MWh................. $ 78.32 $ 61.03 $ 73.50 $ 61.96
Average cost of natural gas:
Fuel expense (in thousands).................................... $ 1,567,504 $ 1,052,309 $ 3,336,248 $ 2,671,860
Gas pipeline charge elimination (1)............................ 1,803 3,118 6,738 14,509
Spread on sales of purchased gas for hedging and optimization.. 27,501 5,640 49,625 (14,660)
Fuel expense related to power generation in
mark-to-market activities, net................................ 56,301 -- 110,790 --
------------- -------------- ------------- --------------
Adjusted fuel expense.......................................... $ 1,653,109 $ 1,061,067 $ 3,503,401 $ 2,671,709
MMBtu of fuel consumed by generating plants (in thousands)..... 189,321 178,868 451,480 444,460
Average cost of natural gas per MMBtu.......................... $ 8.73 $ 5.93 $ 7.76 $ 6.01
MWh generated (in thousands)................................... 28,709 26,604 68,240 64,357
Average cost of adjusted fuel expense per MWh.................. $ 57.58 $ 39.88 $ 51.34 $ 41.51
Average spark spread:
Adjusted electricity and steam revenue (in thousands).......... $ 2,248,409 $ 1,623,684 $ 5,015,601 $ 3,987,826
Less: Adjusted fuel expense (in thousands)..................... 1,653,109 1,061,067 3,503,401 2,671,709
------------- ------------- ------------- -------------
Spark spread (in thousands).................................... $ 595,300 $ 562,617 $ 1,512,200 $ 1,316,117
MWh generated (in thousands)................................... 28,709 26,604 68,240 64,357
Average spark spread per MWh................................... $ 20.74 $ 21.15 $ 22.16 $ 20.45
(table continues)
- 82 -
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2005 2004 2005 2004
------------- ------------- ------------- --------------
(In thousands)
Average POX per normalized MWh
(for comparison purposes we also include POX per actual MWh):
Average total consolidated gross MW in operations.............. 26,126 24,230 25,079 22,146
Hours in the period............................................ 2,208 2,208 6,552 6,576
Total potential MWh............................................ 57,686 53,500 164,318 145,632
Normalized MWh (at 70% capacity factor)........................ 40,380 37,450 115,022 101,942
Plant operating expense (POX).................................. $ 180,336 $ 159,957 $ 555,433 $ 522,237
POX per normalized MWh......................................... $ 4.47 $ 4.27 $ 4.83 $ 5.12
Actual MWh generated (in thousands)............................ 28,709 26,604 68,240 64,357
------------- ------------- ------------- -------------
POX per actual MWh............................................. $ 6.28 $ 6.01 $ 8.14 $ 8.11
------------- ------------- ------------- -------------
- ------------
<FN>
(1) In prior year periods, "gas pipeline charges" also included some small
amounts for fuel charges related to gas assets since sold but not
reclassified to discontinued operations.
</FN>
The table below provides additional detail of total mark-to-market
activity. For the three and nine months ended September 30, 2005 and 2004,
mark-to-market activities, net consisted of (dollars in thousands):
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2005 2004 2005 2004
------------- ------------- ------------- --------------
Realized:
Power activity
"Trading Activity" as defined in EITF No. 02-03................ $ 120,455 $ 9,412 $ 202,939 $ 39,258
Other mark-to-market activity (1).............................. (946) (434) (9,607) (6,378)
------------- ------------- ------------- -------------
Total realized power activity................................. $ 119,509 $ 8,978 $ 193,332 $ 32,880
============= ============= ============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03................ $ (53,280) $ 9,679 $ (96,030) $ 9,548
Other mark-to-market activity (1).............................. (286) -- (286) --
------------- ------------- ------------- -------------
Total realized gas activity................................... $ (53,566) $ 9,679 $ (96,316) $ 9,548
============= ============= ============= =============
Total realized activity:
"Trading Activity" as defined in EITF No. 02-03................ $ 67,175 $ 19,091 $ 106,909 $ 48,806
Other mark-to-market activity (1).............................. (1,232) (434) (9,893) (6,378)
------------- ------------- ------------- -------------
Total realized activity....................................... $ 65,943 $ 18,657 $ 97,016 $ 42,428
============= ============= ============= =============
Unrealized:
Power activity
"Trading Activity" as defined in EITF No. 02-03................ $ (129,578) $ (17,057) $ (127,094) $ (40,926)
Ineffectiveness related to cash flow hedges.................... (1,643) 1,142 (1,947) 1,268
Other mark-to-market activity (1).............................. 1,935 (240) 3,681 (13,015)
------------- ------------- ------------- -------------
Total unrealized power activity............................... $ (129,286) $ (16,155) $ (125,360) $ (52,673)
============= ============= ============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03................ $ 94,546 $ (8,508) $ 58,124 $ (11,610)
Ineffectiveness related to cash flow hedges.................... 9,651 777 10,417 6,540
Other mark-to-market activity (1).............................. -- -- -- --
------------- ------------- ------------- -------------
Total unrealized gas activity................................. $ 104,197 $ (7,731) $ 68,541 $ (5,070)
============= ============= ============= =============
Total unrealized activity:
"Trading Activity" as defined in EITF No. 02-03.................. $ (35,032) $ (25,565) $ (68,970) $ (52,536)
Ineffectiveness related to cash flow hedges...................... 8,008 1,919 8,470 7,808
Other mark-to-market activity (1)................................ 1,935 (240) 3,681 (13,015)
------------- ------------- ------------- -------------
Total unrealized activity..................................... $. (25,089) $ (23,886) $ (56,819) $ (57,743)
============= ============= ============= =============
Total mark-to-market activity:
"Trading Activity" as defined in EITF No. 02-03.................. $ 32,143 $ (6,474) $ 37,939 $ (3,730)
Ineffectiveness related to cash flow hedges...................... 8,008 1,919 8,470 7,808
Other mark-to-market activity (1)................................ 703 (674) (6,212) (19,393)
------------- ------------- ------------- -------------
Total mark-to-market activity................................. $ 40,854 $ (5,229) $ 40,197 $ (15,315)
============= ============= ============= =============
- ------------
(table continues)
- 83 -
<FN>
(1) Activity related to our assets but does not qualify for hedge accounting.
</FN>
Overview
Summary of Key Activities Through September 30, 2005
Finance -- New Issuances and Amendments:
Date Amount Description
- ---------------------- ---------------- ------------------------------------------------------------------------------------------
8/12/05............... $150.0 million CCFC LLC completes a $150.0 million private placement of Class A Redeemable Preferred
Shares; the preferred shares are repurchased in full on October 14, 2005
Finance -- Repurchases and Extinguishments:
Date Amount Description
- ---------------------- ---------------- ------------------------------------------------------------------------------------------
7/12/05............... $138.9 million Purchase $138.9 million aggregate principal of outstanding First Priority Notes pursuant
to a tender offer commenced June 9, 2005
7/13/05............... $517.5 million Repay the convertible debentures payable to Calpine Capital Trust III, the issuer of the
HIGH TIDES III preferred securities, the proceeds of which are applied by the Trust to
redeem the HIGH TIDES III preferred securities in full
7/1/05-9/30/05........ $263.5 million Repurchase Senior Notes in open market transaction totaling $263.5 million in principal
for cash of $233.9 million plus accrued interest
Asset Sales:
Date Description
- ---------------------- ------------------------------------------------------------------------------------------------------------
7/7/05................ Complete the sale of substantially all remaining oil and gas exploration and production properties and
assets for $1.05 billion, less adjustments, transaction fees, and expenses
7/8/05................ Complete the sale of 50% interest in the 175-MW Grays Ferry power plant for gross proceeds of $37.4 million
7/28/05............... Complete the sale of Saltend, a 1,200-MW power plant in Hull, England, for $862.9 million
7/29/05............... Complete the sale of Inland Empire Energy Center development project to GE for approximately $30.9 million
8/2/05................ Complete the sale of the 156-MW Morris power plant for $84.5 million
8/16/05............... Agree to sell 561-MW Ontelaunee; the sale is consummated on October 6, 2005, for $225 million less
adjustments, transaction fees and expenses
Power Plant Development and Construction:
Date Project Description
- ---------------------- --------------------------------- --------------------
7/1/05................ Bethpage Energy Center 3 Commercial Operation
7/5/05................ Pastoria Energy Center (Phase II) Commercial Operation
Other:
Date Description
- ---------------------- ------------------------------------------------------------------------------------------------------------
7/5/05................ Sign an agreement with Siemens-Westinghouse to restructure the long-term relationship, which is expected to
provide additional flexibility to self-perform maintenance work in the future
7/7/05................ Announce a 15-year Master Products and Services Agreement with GE to supplement operations with a variety of
services and to lower operating costs
7/11/05............... Major merchant power generator selects PSM to install LEC-III (R) and eliminate 90% of the power plant's
nitrogen oxide emissions
8/26/05............... CES announces new service agreements with Project Orange Associates LLC and the Greater Toronto Airports
Authority to provide them with marketing, scheduling, and other energy managements services
8/29/05............... CES announces five year long-term power supply agreement for 170-MW of electricity with Tampa Electric
Company
9/7/05................ Agreed to form an energy marketing and trading venture with Bear Stearns Companies, Inc.( Bear Stearns).
The new energy venture is expected to develop a third-party customer business focused on physical natural
gas and power trading and related structured transactions. Regulatory approval was received on
Oct. 31, 2005, and it is anticipated that operations will begin in the fourth quarter of 2005.
- 84 -
California Power Market
The volatility in the California power market from mid-2000 through
mid-2001 has produced significant unanticipated results. The unresolved issues
arising in that market, where 41 of our 95 power plants are located, could
adversely affect our performance. See Note 14 of the Notes to Consolidated
Condensed Financial Statements for a further discussion.
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, 2005 through September 30, 2005, is summarized in the table
below (in thousands):
Fair value of contracts outstanding at January 1, 2005.......................................................... $ 37,863
Cash losses recognized or otherwise settled during the period (1)............................................... 1,310
Non-cash gains recognized or otherwise settled during the period (2)............................................ 38,125
Changes in fair value attributable to new contracts (3)......................................................... (331,155)
Changes in fair value attributable to price movements (4)....................................................... (245,081)
--------------
Fair value of contracts outstanding at September 30, 2005..................................................... $ (498,938)
==============
Realized cash flow from fair value hedges (5)................................................................... $ 181,097
==============
- ------------
<FN>
(1) Realized losses from cash flow hedges and mark-to-market activity are
reflected in the tables below (in millions):
Realized value of cash flow hedges (a).......................................................................... $ (292.1)
Net of:
Terminated and monetized derivatives.......................................................................... (23.2)
Equity method hedges.......................................................................................... 2.0
Hedges reclassified to discontinued operations................................................................ (199.4)
--------------
Cash losses realized from cash flow hedges.................................................................... $ (71.5)
--------------
Realized value of mark-to-market activity (b)................................................................... $ 97.0
Net of:
Non-cash realized mark-to-market activity..................................................................... 26.8
--------------
Cash gains realized on mark-to-market activity................................................................ 70.2
--------------
Cash losses recognized or otherwise settled during the period................................................. $ (1.3)
==============
(a) Realized value as disclosed in Note 9 of the Notes to Consolidated
Condensed Financial Statements
(b) Realized value as reported in Management's discussion and analysis of
operating performance metrics
(2) This represents the non-cash amortization of deferred items embedded in our
derivative assets and liabilities.
(3) The change attributable to new contracts includes the $292.4 million
derivative liability associated with a transaction by our Deer Park
facility as discussed in Note 9 of the Notes to Consolidated Condensed
Financial Statements.
(4) Net commodity derivative assets reported in Note 9 of the Notes to
Consolidated Condensed Financial Statements.
(5) 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.
</FN>
- 85 -
The fair value of outstanding derivative commodity instruments at September
30, 2005, based on price source and the period during which the instruments will
mature, are summarized in the table below (in thousands):
Fair Value Source 2005 2006-2007 2008-2009 After 2009 Total
- ---------------------------------------------------- ---------- ---------- ---------- ---------- ----------
Prices actively quoted ............................. $ 142,702 $ 63,809 $ -- $ -- $ 206,511
Prices provided by other external sources .......... (211,699) (382,774) 3,414 (33,729) (624,788)
Prices based on models and other
valuation methods ................................ -- 189 (56,563) (24,287) (80,661)
--------- --------- --------- --------- ---------
Total fair value ................................. $ (68,997) $(318,776) $ (53,149) $ (58,016) $(498,938)
========= ========= ========= ========= =========
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, 2005, and the
period during which the instruments will mature are summarized in the table
below (in thousands):
Credit Quality 2005 2006-2007 2008-2009 After 2009 Total
- ---------------------------------------------------- ---------- ---------- ---------- ---------- ----------
(Based on Standard & Poor's Ratings
as of September 30, 2005)
Investment grade.................................... $ (79,177) $(316,713) $ (53,065) $ (58,016) $(506,971)
Non-investment grade................................ 11,699 1,704 (20) -- 13,383
No external ratings................................. (1,519) (3,767) (64) -- (5,350)
--------- --------- --------- --------- ---------
Total fair value.................................. $ (68,997) $(318,776) $ (53,149) $ (58,016) $(498,938)
========= ========= ========= ========= =========
The fair value of outstanding derivative commodity instruments and the fair
value that would be expected after a ten percent adverse price change are shown
in the table below (in thousands):
Fair Value
After 10%
Adverse
Fair Value Price Change
------------ --------------
At September 30, 2005:
Electricity............................. $ (1,060,248) $ (1,373,769)
Natural gas............................. 561,310 387,411
------------ ------------
Total................................. $ (498,938) $ (986,358)
=========== ============
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 10% 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 10% change in prices, the fair value of our derivative portfolio would
typically change by more than 10% for earlier forward months and less than 10%
for later forward months because of the higher volatilities in the near term and
the effects of discounting expected future cash flows.
The primary factors affecting the fair value of our derivatives at any
point in time are (1) the volume of open derivative positions (MMBtu and MWh),
and (2) changing commodity market prices, principally for electricity and
natural gas. The total volume of open gas derivative positions increased by 44%
- 86 -
from December 31, 2004, to September 30, 2005, and the total volume of open
power derivative positions increased by 135% 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, "Accounting for Derivative
Instruments and Hedging Activities," the change since the last balance sheet
date in the total value of the derivatives (both assets and liabilities) is
reflected either in OCI, net of tax, or in the statement of operations as an
item (gain or loss) of current earnings. As of September 30, 2005, 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, 2005, have reflected this. See Notes 9 and 10 of the Notes to
Consolidated Condensed Financial Statements for additional information on
derivative activity.
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, 2005 (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
- ----------------------------------------------------- ----------------- --------------- ----------------------- ---------------
2009.................................................. $ 50,000 4.8% 3-month US $LIBOR $ (488)
2011.................................................. 57,291 4.5% 3-month US $LIBOR (11)
2011.................................................. 287,447 4.5% 3-month US $LIBOR (44)
2011.................................................. 201,003 4.4% 3-month US $LIBOR 725
2011.................................................. 40,062 4.4% 3-month US $LIBOR 145
2011.................................................. 12,347 6.9% 3-month US $LIBOR (2,554)
2011.................................................. 50,300 4.9% 3-month US $LIBOR (647)
2011.................................................. 24,695 4.8% 3-month US $LIBOR (495)
2011.................................................. 12,347 4.8% 3-month US $LIBOR (248)
2011.................................................. 15,986 4.9% 3-month US $LIBOR (323)
2011.................................................. 15,986 4.9% 3-month US $LIBOR (323)
2011.................................................. 12,347 4.8% 3-month US $LIBOR (248)
2011.................................................. 15,986 4.9% 3-month US $LIBOR (323)
2011.................................................. 12,347 4.8% 3-month US $LIBOR (248)
2012.................................................. 100,926 6.5% 3-month US $LIBOR (7,742)
2016.................................................. 20,355 7.3% 3-month US $LIBOR (2,907)
2016.................................................. 13,570 7.3% 3-month US $LIBOR (1,936)
2016.................................................. 40,710 7.3% 3-month US $LIBOR (5,809)
2016.................................................. 27,140 7.3% 3-month US $LIBOR (3,872)
2016.................................................. 33,925 7.3% 3-month US $LIBOR (4,841)
-------------- --------------
Total.............................................. $ 1,044,770 5.1% $ (32,189)
============== ==============
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% $ (6,520)
2011.................................................. 100,000 6-month US $LIBOR 8.5% (7,442)
2011.................................................. 100,000 6-month US $LIBOR 8.5% (5,090)
2011.................................................. 200,000 6-month US $LIBOR 8.5% (10,465)
-------------- --------------
Total.............................................. $ 500,000 8.5% $ (29,517)
============== ==============
- 87 -
The fair value of outstanding interest rate swaps and the fair value that
would be expected after a 1% adverse interest rate change are shown in the table
below (in thousands):
Fair Value After a
1.0%
(100 Basis Point)
Adverse
Net Fair Value as of September 30, 2005 Interest Rate Change
- --------------------------------------- ---------------------
$(61,706)............................................ $ (82,200)
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," ("SFAS No. 52") 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, 2005, 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...................................... $ (14,758)
$Cdn-$US...................................... (131,367)
$Cdn-GBP...................................... (13,885)
Other......................................... (1,869)
In prior periods, we reported significant unhedged positions and
corresponding foreign currency transaction gains and losses due to our exposure
to changes in the GBP-$US exchange rate. As a result of the sale of Saltend (see
Note 8 of the Notes to Consolidated Condensed Financial Statements for more
information), effectively all of our GBP-$US accounting exposure has been
eliminated. We expect that currency movements will continue to create volatility
within our pre-tax earnings in future periods, but such volatility is not
expected to result from movements in the GBP-$US exchange rate.
Significant changes in exchange rates will also impact our 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 2004. During 2004, our CTA increased by
approximately $62 million primarily due to a strengthening of the Canadian
dollar and GBP against the U.S. dollar by approximately 7% each.
Foreign Currency Transaction Gain (Loss)
Three Months Ended September 30, 2005, Compared to Three Months Ended
September 30, 2004:
The major components of our foreign currency transaction losses from
continuing operations of $43.9 million and $12.4 million for the three months
ended September 30, 2005 and 2004, respectively, are as follows (amounts in
millions):
2005 2004
-------- --------
Loss from $Cdn-$US fluctuations............................ $ (54.6) $ (8.6)
Loss from GBP-Euro fluctuations............................ (2.0) (4.1)
Gain (Loss) from $Cdn-GBP fluctuations..................... 12.8 --
Gain (Loss) from other currency fluctuations............... (0.1) 0.3
------- -------
Total................................................... $ (43.9) $ (12.4)
======= =======
The $Cdn-$US loss for the three months ended September 30, 2005, was due
primarily to a significant weakening of the U.S. dollar against the Canadian
dollar during the third quarter of 2005. In September 2004, we sold
substantially all of our oil and gas assets in Canada, which significantly
reduced the degree to which we could designate our $Cdn-denominated liabilities
as hedges against our investment in Canadian dollar denominated subsidiaries. As
a result, we are now considerably more exposed to fluctuations in the $Cdn-$US
exchange rate as we hold several significant $Cdn-denominated liabilities that
can no longer be hedged under SFAS No. 52. When the U.S. dollar weakened during
- 88 -
the third quarter of 2005, significant re-measurement losses were triggered on
these loans. These losses 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 under SFAS
No. 52. While re-measurement gains and losses associated with the loan are
recorded within CTA, the re-measurement of the underlying interest receivable
every period continues to be recorded as a component of net income due to the
fact that the interest is physically settled semi-annually.
The $Cdn-$US loss for the three months ended September 30, 2004, was
moderate despite the fact that the U.S. dollar weakened considerably against the
Canadian dollar during the third quarter of 2004. The primary reason for this
was because the majority of our existing $Cdn-$US exposures were effectively
designated as hedges of our net investment in Canadian dollar subsidiaries
through early September 2004. As a result, re-measurement losses that otherwise
would have been recognized within our Consolidated Condensed Statements of
Operations were recorded within CTA in accordance with SFAS No. 52. In September
2004, we completed the sale of our Canadian oil and gas assets and subsequent to
this transaction, the Canadian dollar strengthened considerably against the U.S.
dollar for the rest of the month. The loss of the majority of our natural hedge
position combined with the strengthened Canadian dollar created the majority of
the $Cdn-$US loss of $8.6 million for the three months ended September 30, 2004.
The loss recognized was 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 under SFAS No. 52
as described above.
During the three months ended September 30, 2005 and 2004, respectively,
the Euro strengthened against the GBP, triggering re-measurement losses
associated with our Euro-denominated 8 3/8% Senior Notes Due 2008.
The primary driver behind our gain of $12.8 million from other $Cdn-GBP
fluctuations for the three months ended September 30, 2005, was due to the sale
of Saltend in July 2005, combined with a subsequent strengthening of the
Canadian dollar against the GBP. One of our $Cdn-denominated subsidiaries holds
a significant GBP-denominated liability position which relates to financing
borrowed for the original purchase of Saltend in 2001. Prior to the sale, this
liability position was designated as a hedge of the subsidiary's net investment
in Saltend and as a result, all re-measurement gains and losses associated with
the liability were recorded within CTA in accordance with SFAS No. 52.
Subsequent to the sale, all such re-measurement gains and losses are required to
be recorded within net income as we no longer own a GBP-denominated investment
to hedge against. The strengthening of the Canadian dollar against the GBP
during the third quarter of 2005 created significant re-measurement gains on
this newly exposed liability position. For the three months ended September 30,
2004, our $Cdn-GBP liability position was effectively hedged and as a result,
all re-measurement gains and losses were recorded as a component of CTA.
Nine Months Ended September 30, 2005, Compared to Nine Months Ended
September 30, 2004:
The major components of our foreign currency transaction losses of $18.3
million and $7.6 million, respectively, for the nine months ended September 30,
2005 and 2004, respectively, are as follows (amounts in millions):
2005 2004
-------- --------
Loss from $Cdn-$US fluctuations............................ $ (35.6) $ (14.0)
Gain from GBP-Euro fluctuations............................ 7.6 6.5
Gain (Loss) from $Cdn-GBP fluctuations..................... 11.9 --
Loss from other currency fluctuations...................... (2.2) (0.1)
------- -------
Total...................................................... $ (18.3) $ (7.6)
======= =======
The $Cdn-$US loss for the nine months ended September 30, 2005, was due
primarily to a significant weakening of the U.S. dollar against the Canadian
dollar, most significantly within the third quarter of 2005. In September 2004,
we sold substantially all of our oil and gas assets in Canada, which
significantly reduced the degree to which we could designate our
$Cdn-denominated liabilities as hedges against our investment in Canadian dollar
denominated subsidiaries. As a result, we are now considerably more exposed to
fluctuations in the $Cdn-$US exchange rate as we hold several significant
$Cdn-denominated liabilities that can no longer be hedged under SFAS No. 52.
When the U.S. dollar weakened, significant re-measurement losses were triggered
on these loans. These losses 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 under SFAS
No. 52. While re-measurement gains and losses associated with the loan are
recorded within CTA, the re-measurement of the underlying interest receivable
every period continues to be recorded as a component of net income due to the
fact that the interest is physically settled semi-annually.
- 89 -
The $Cdn-$US loss for the nine months ended September 30, 2004 was due to
two primary reasons. First, in September 2004, we completed the sale of our
Canadian oil and gas assets and subsequent to this transaction, the Canadian
dollar strengthened considerably against the U.S. dollar for the rest of the
month. The sale eliminated the majority of our natural hedge position as
described above, resulting in a large open exposure that was susceptible to
volatility in the $Cdn-$US exchange rate. Second, 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
during this period. As noted above, physical settlement of the interest
receivable occurs semi-annually, in May and November. As a result, the most
significant re-measurement gains and losses associated with this receivable
generally occur within 1-2 months of the payment date, as the receivable
approaches its full value for the 6-month period. From January to May 2004, the
U.S. dollar strengthened considerably against the Canadian dollar while the
interest receivable balance grew significantly, resulting in large
re-measurement losses. These losses were partially offset during the third
quarter of 2004 as the Canadian dollar strengthened against the U.S. dollar, but
the average interest receivable balance outstanding during the third quarter was
not as large as the balance outstanding in March and April, resulting in a net
loss for the nine months ended September 30, 2004.
During the nine months ended September 30, 2005 and 2004, respectively, the
Euro weakened against the GBP, triggering re-measurement gains associated with
our Euro-denominated 8 3/8% Senior Notes Due 2008.
The primary driver behind our gain of $11.9 million from other $Cdn-GBP
fluctuations for the nine months ended September 30, 2005, was due to the sale
of Saltend in July 2005, combined with a subsequent strengthening of the
Canadian dollar against the GBP. One of our $Cdn-denominated subsidiaries holds
a significant GBP-denominated liability position which relates to financing
borrowed for the original purchase of Saltend in 2001. Prior to the sale, this
liability position was designated as a hedge of the subsidiary's net investment
in Saltend and as a result, all re-measurement gains and losses associated with
the liability were recorded within CTA in accordance with SFAS No. 52.
Subsequent to the sale, all such re-measurement gains and losses are required to
be recorded within net income as we no longer own a GBP-denominated investment
to hedge against. The strengthening of the Canadian dollar against the GBP
during the third quarter of 2005 created significant re-measurement gains on
this newly exposed liability position. For the nine months ended September 30,
2004, our $Cdn-GBP liability position was effectively hedged and as a result,
all re-measurement gains and losses were recorded as a component of CTA.
The primary driver behind our loss of $2.2 million from other currency
fluctuations for the nine months ended September 30, 2005 was a significant
strengthening of the U.S. dollar against the Euro, and its impact on certain
U.S. dollar-denominated intercompany trade payables owed by our TTS subsidiary.
By contrast, movement in the $US-Euro exchange rate was relatively flat for the
nine months ended September 30 2004 and as a result, minimal re-measurement
losses were created.
Available-for-Sale Debt Securities -- On July 13, 2005, we completed the
redemption of all of the outstanding HIGH TIDES III preferred securities and of
the underlying convertible debentures. Accordingly, the HIGH TIDES III preferred
securities repurchased by us are no longer outstanding. See Notes 4 and 7 of the
Notes to Consolidated Condensed Financial Statements for further information.
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 the
CalGen floating rate notes, institutional term loans and revolving credit
facility. Borrowings under our $200 million CalGen revolving credit agreement
are used primarily for letters of credit in support of gas purchases, power
contracts and transmission, and was available for the construction costs of the
Pastoria Energy Center expansion project, which was completed in July 2005.
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.
On August 12, 2005, we issued $150.0 million of Class A Redeemable
Preferred Shares due February 13, 2006, through our wholly owned indirect
subsidiary, CCFC LLC, which is an indirect parent of CCFC I. The Redeemable
Preferred Shares bear an initial dividend rate of LIBOR plus 950 basis points
and may be redeemed in whole or in part at any time by the issuer at par plus
accrued dividends. The Redeemable Preferred Shares were repurchased in full on
October 14, 2005.
- 90 -
The following table summarizes by maturity date our variable-rate debt
exposed to interest rate risk as of September 30, 2005. All fair market values
are shown net of applicable premium or discount, if any (dollars in thousands):
2005 2006 2007 2008
---------- ---------- ---------- ----------
3-month US $LIBOR weighted average interest rate basis (4)
MEP Pleasant Hill Term Loan, Tranche A ........................... $ 2,528 $ 7,482 $ 8,132 $ 9,271
Riverside Energy Center project financing ........................ -- 3,685 3,685 3,685
Rocky Mountain Energy Center project financing ................... -- 2,649 2,649 2,649
---------- ---------- ---------- ----------
Total of 3-month US $LIBOR rate debt ........................... 2,528 13,816 14,466 15,605
1-month EURLIBOR weighted average interest rate basis (4)
Thomassen revolving line of credit ............................... 2,417 -- -- --
---------- ---------- ---------- ----------
Total of 1-month EURLIBOR rate debt ............................ 2,417 -- -- --
1-month US $LIBOR weighted average interest rate basis (4)
First Priority Secured Floating Rate Notes Due 2009
(CalGen) ........................................................ -- -- 1,175 2,350
---------- ---------- ---------- ----------
Total of 1-month US $LIBOR weighted average
interest rate debt ............................................ -- -- 1,175 2,350
1-month US $LIBOR interest rate basis (4)
Freeport Energy Center project financing ......................... -- -- 1,969 1,810
Mankato Energy Center project financing .......................... -- -- 1,727 1,781
---------- ---------- ---------- ----------
Total 1-month US $LIBOR interest rate .......................... -- -- 3,696 3,591
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 ........................... -- -- -- --
(1)(4)
Class A Redeemable Preferred Shares (CCFC) ....................... -- 150,000 -- --
Metcalf Energy Center, LLC preferred interest .................... -- -- -- --
First Priority Secured Institutional Term Loan Due 2009
(CCFC I) ........................................................ -- 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 ............ -- 153,208 3,208 3,208
(2)(4)
Second Priority Senior Secured Term Loan B Notes
Due 2007 ........................................................ 1,875 7,500 725,625 --
---------- ---------- ---------- ----------
Total of variable rate debt as defined at (2) below ............ 1,875 7,500 725,625 --
(3)(4)
Second Priority Senior Secured Floating Rate Notes
Due 2007 ........................................................ 1,250 5,000 483,750 --
Blue Spruce Energy Center project financing ...................... 938 3,750 3,750 3,750
---------- ---------- ---------- ----------
Total of variable rate debt as defined at (3) below ............ 2,188 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
Metcalf Energy Center, LLC project financing ..................... -- -- -- --
---------- ---------- ---------- ----------
Total of variable rate debt as defined at (5) below ............ -- -- 3,000 9,700
---------- ---------- ---------- ----------
(6)(4)
Island Cogen ..................................................... 9,860 -- -- --
Contra Costa ..................................................... -- 171 179 187
---------- ---------- ---------- ----------
Total of variable rate debt as defined at (6) below ............ 9,860 171 179 187
---------- ---------- ---------- ----------
Grand total variable-rate debt instruments (8) ............... $ 18,868 $ 183,445 $1,238,849 $ 38,391
========== ========== ========== ==========
- 91 -
2009 Thereafter September 30, 2005 (7)
----------- ---------- ----------------------
3-month US $LIBOR weighted average interest rate basis (4)
MEP Pleasant Hill Term Loan, Tranche A .................................... $ 9,433 $ 85,479 $ 122,325
Riverside Energy Center project financing ................................. 3,685 340,553 355,293
Rocky Mountain Energy Center project financing ............................ 2,649 235,276 245,872
----------- ---------- -----------
Total of 3-month US $LIBOR rate debt .................................... 15,767 661,308 723,490
1-month EURLIBOR weighted average interest rate basis (4)
Thomassen revolving line of credit ........................................ -- -- 2,417
----------- ---------- -----------
Total of 1-month EURLIBOR rate debt ..................................... -- -- 2,417
1-month US $LIBOR weighted average interest rate basis (4)
First Priority Secured Floating Rate Notes Due 2009 (CalGen) .............. 231,475 -- 235,000
----------- ---------- -----------
Total of 1-month US $LIBOR weighted average interest rate debt .......... 231,475 -- 235,000
1-month US $LIBOR interest rate basis (4)
Freeport Energy Center project financing .................................. 1,600 122,058 127,437
Mankato Energy Center project financing ................................... 1,530 112,500 117,538
----------- ---------- -----------
Total 1-month US $LIBOR interest rate ................................... 3,130 234,558 244,975
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
(1)(4)
Class A Redeemable Preferred Shares (CCFC) ................................ -- -- 150,000
Metcalf Energy Center, LLC preferred interest ............................. -- 155,000 155,000
First Priority Secured Institutional Term Loan Due 2009
(CCFC I) ................................................................. 365,189 -- 374,813
Second Priority Senior Secured Floating Rate Notes Due 2011
(CCFC I) ................................................................. -- 409,296 409,296
----------- ---------- -----------
Total of variable rate debt as defined at (1) below ..................... 365,189 564,296 1,089,109
(2)(4)
Second Priority Senior Secured Term Loan B Notes Due 2007 ................. -- -- 565,950
----------- ---------- -----------
Total of variable rate debt as defined at (2) below ..................... -- -- 565,950
(3)(4)
Second Priority Senior Secured Floating Rate Notes Due 2007 ............... -- -- 377,300
Blue Spruce Energy Center project financing ............................... 3,750 81,395 97,333
----------- ---------- -----------
Total of variable rate debt as defined at (3) below ..................... 3,750 81,395 474,633
(5)(4)
First Priority Secured Term Loans Due 2009 (CalGen) ....................... 591,000 -- 600,000
Second Priority Secured Floating Rate Notes Due 2010 (CalGen) ............. 6,400 623,239 632,839
Second Priority Secured Term Loans Due 2010 (CalGen) ...................... 1,000 97,381 98,881
Metcalf Energy Center, LLC project financing .............................. -- 100,000 100,000
----------- ---------- -----------
Total of variable rate debt as defined at (5) below ..................... 598,400 820,620 1,431,720
----------- ---------- -----------
(6)(4)
Island Cogen ................................................................ -- -- 9,860
Contra Costa ................................................................ 196 1,381 2,114
----------- ---------- -----------
Total of variable rate debt as defined at (6) below ..................... 196 1,381 11,974
----------- ---------- -----------
Grand total variable-rate debt instruments (8) ......................... $ 1,217,907 $3,043,558 $ 5,459,268
=========== ========== ===========
- ------------
<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) Fair value equals carrying value, with the exception of the Second-Priority
Senior Secured Term B Loans Due 2007 and Second-Priority Senior Secured
Floating Rate Notes Due 2007, which are shown at quoted trading values as
of September 30, 2005.
(table continues)
- 92 -
(8) The aggregate principal amount subject to variable interest rate risk was
$5,741.0 million as of September 30, 2005.
</FN>
New Accounting Pronouncements (See Note 2 of the Notes to Consolidated Condensed
Financial Statements for a discussion of new accounting pronouncements)
Summary of Dilution Potential of Our Contingent Convertible Notes: 2023
Convertible Notes, 2015 Convertible Notes and 2014 Convertible Notes -- The
table below assumes normal conversion for the 2014 Convertible Notes, 2015
Convertible Notes and 2023 Convertible 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 three
contingent convertible notes issuances and does not include the potential
dilutive effect of the now fully redeemed HIGH TIDES III preferred securities,
the remaining 2006 Convertible Notes or employee stock options. Additionally, we
are still assessing the potential impact of the SFAS No. 128-R exposure draft on
our three series of contingent convertible securities. See Notes 2 and 11 of the
Notes to Consolidated Condensed Financial Statements for more information.
2014 2015 2023
Convertible Convertible Convertible
Notes Notes Notes
------------- ------------- --------------
Aggregate outstanding principal amount at maturity............................ $ 641,685,000 $ 650,000,000 $ 633,775,000
Conversion price per share.................................................... $ 3.85 $ 4.00 $ 6.50
Conversion rate............................................................... 259.7402 250.0000 153.8462
Trigger price (20% over conversion price)..................................... $ 4.62 $ 4.80 $ 7.80
Additional Shares
2014 2015 2023
Convertible Convertible Convertible Share Share Dilution
Future Calpine Common Stock Price Notes (2) Notes Notes Subtotal Increase in EPS
- --------------------------------------- --------------- ---------------- ---------------- ---------------- ---------- --------
$5.00.................................. 38,334,429 32,500,000 -- 70,834,429 14.8% 12.9%
$7.50.................................. 81,113,429 75,833,333 13,000,542 169,947,304 35.6% 26.2%
$10.00................................. 102,502,929 97,500,000 34,126,375 234,129,304 49.0% 32.9%
$20.00................................. 134,587,179 130,000,000 65,815,125 330,402,304 69.2% 40.9%
$40.00................................. 150,629,304 146,250,000 81,659,500 378,538,804 79.2% 44.2%
$100.00................................ 160,254,579 156,000,000 91,166,125 407,420,704 85.3% 46.0%
Common shares outstanding at
September 30, 2005 (1)............... 478,964,218
- ------------
<FN>
(1) Excludes the 89 million shares issued under the Share Lending Agreement
(see Note 11 of the Notes to Consolidated Condensed Financial Statements)
and excludes our contingently issuable restricted stock.
(2) In the case of the 2014 Convertible Notes, more shares could be issued when
the accreted value is less than $1,000 than in the table above since,
generally, the accreted value (initially $839 per bond) is paid in cash,
and the balance of the conversion value is paid in shares. The maximum
potential incremental shares assuming conversion when the accreted value is
$839 per bond are shown in the table below:
Incremental
Future Calpine Common Stock Price Shares
--------------------------------- -----------
$5.00.................................................20,662,257
$7.50.................................................13,774,838
$10.00................................................10,331,129
$20.00.................................................5,165,564
$40.00.................................................2,582,782
$100.00................................................1,033,113
</FN>
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in Item 2.
- 93 -
Item 4. Controls and Procedures.
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure
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 SEC rules and forms, and that such
information is accumulated and communicated to our management, including our
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.
As of December 31, 2004, management identified a material weakness related
to our tax accounting processes, procedures and controls that was discussed in
Item 9A of the Company's 2004 Form 10-K. During the first three quarters of
2005, we have taken steps necessary to improve our internal controls relating to
the preparation and review of interim and annual income tax provisions and to
remediate this material weakness. While significant progress has been made in
the remediation of these controls, the controls have not yet operated for a
sufficient period of time to allow us to complete the required testing and to
conclude that they are designed and operating effectively.
Our senior management, including our Chief Executive Officer and Chief
Financial Officer, evaluated the effectiveness of our disclosure controls and
procedures as of the end of the period covered by this quarterly report. Based
on the status of the remediation of the material weakness, our Chief Executive
Officer and our Chief Financial Officer concluded that our disclosure controls
and procedures are not effective. We continue to perform additional analysis and
post-closing procedures to ensure our consolidated financial statements are
prepared in accordance with GAAP. Accordingly, management believes that the
financial statements included in this report fairly present in all material
respects our financial condition, results of operations and cash flows for the
periods presented. The certificates required by this item are filed as Exhibits
31.1, 31.2 and 32.1 to this Form 10-Q.
Status of Remediation of the Material Weakness
During the first three quarters of 2005, we have taken the steps necessary
to improve our internal controls relating to the preparation and review of
interim and annual income tax provisions, including the accounting for current
income taxes payable and deferred income tax assets and liabilities. We have
hired additional resources and have engaged third party tax experts to improve
the effectiveness of the controls over management's review of the details of the
income tax calculations. We have also improved the process of preparing and
reviewing the workpapers supporting our tax related calculations and
conclusions.
We will continue to do the following:
o Complete the implementation of the CorpTax computer application and
enhance other financial applications to automate more of the tax
analysis and provision processes and continue to improve the clarity
of supporting documentation and reports, and
o Add additional resources in the tax department as well as provide tax
accounting training for key personnel.
We continue to monitor the effectiveness of the tax controls and procedures
and will make any additional changes that management deems appropriate.
Changes in Internal Control Over Financial Reporting
We continuously seek to improve the efficiency and effectiveness of our
internal controls. This results in refinements to processes throughout the
Company. During the first three quarters of 2005, there were no significant
changes in our internal control over financial reporting, other than the changes
related to the tax accounting processes, procedures and controls discussed
above, that materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
- 94 -
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings.
See Note 12 of the Notes to Consolidated Condensed Financial Statements for
a description of our legal proceedings.
Item 6. Exhibits.
(a) Exhibits
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
-------------
Exhibit
Number Description
- ------- -----------------------------------------------------------------------
3.1.1 Amended and Restated Certificate of Incorporation of the Company, as
amended through June 2, 2004.(a)
3.1.2 Amendment to Amended and Restated Certificate of Incorporation of the
Company, dated June 20, 2005.(b)
3.2 Amended and Restated By-laws of the Company.(c)
4.1 Amended and Restated Limited Liability Company Agreement of CCFC
Preferred Holdings, LLC containing terms of its Class A Redeemable
Preferred Shares due February 13, 2006.(d)
4.2 Second Amended and Restated Limited Liability Company Operating
Agreement of CCFC Preferred Holdings, LLC, dated as of October 14,
2005, containing terms of its 6-Year Redeemable Preferred Shares Due
2011.(d)
10.1 Purchase and Sale Agreement dated July 7, 2005, by and among Calpine
Gas Holdings LLC, Calpine Fuels Corporation, Calpine Corporation,
Rosetta Resources Inc., and the other Subject Companies identified
therein.(e)
10.2 Master Transaction Agreement, dated September 7, 2005, among Calpine
Corporation, Calpine Energy Services, L.P., The Bear Stearns Companies
Inc., and such other parties as may become party thereto from time to
time. Approximately two pages of this Exhibit 10.2 have been omitted
pursuant to a request for confidential treatment. The omitted language
has been filed separately with the SEC.(*)
10.3 Amendment to 1996 Stock Incentive Plan, as amended.(f)
31.1 Certification of the Chairman, President and Chief Executive Officer
Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.(*)
31.2 Certification of the Executive Vice President and Chief Financial
Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.(*)
32.1 Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.(*)
- ----------
(*) Filed herewith.
(a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q for the quarter ended June 30, 2004, filed with the SEC on August 9,
2004.
(b) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q for the quarter ended June 30, 2005, filed
with the SEC on August 9, 2005.
(c) 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.
(d) This document has been omitted in reliance on Item 601(b)(4)(iii) of
Regulation S-K. Calpine Corporation agrees to furnish a copy of such
document to the SEC upon request.
(continued)
- 95 -
(e) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on July 13, 2005.
(f) Description of such amendment is incorporated by reference to Item 1.01 of
Calpine Corporation's Current Report on Form 8-K filed with the SEC on
September 20, 2005. Such amendment constitutes a management contract or
compensatory plan or arrangement.
- 96 -
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, 2005
By: /s/ CHARLES B. CLARK, JR.
----------------------------------------------
Charles B. Clark, Jr.
Senior Vice President and
Corporate Controller
(Principal Accounting Officer)
Date: November 9, 2005
- 97 -
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
-------------
Exhibit
Number Description
- ------- -----------------------------------------------------------------------
3.1.1 Amended and Restated Certificate of Incorporation of the Company, as
amended through June 2, 2004.(a)
3.1.2 Amendment to Amended and Restated Certificate of Incorporation of the
Company, dated June 20, 2005.(b)
3.2 Amended and Restated By-laws of the Company.(c)
4.1 Amended and Restated Limited Liability Company Agreement of CCFC
Preferred Holdings, LLC containing terms of its Class A Redeemable
Preferred Shares due February 13, 2006.(d)
4.2 Second Amended and Restated Limited Liability Company Operating
Agreement of CCFC Preferred Holdings, LLC, dated as of October 14,
2005, containing terms of its 6-Year Redeemable Preferred Shares Due
2011.(d)
10.1 Purchase and Sale Agreement dated July 7, 2005, by and among Calpine
Gas Holdings LLC, Calpine Fuels Corporation, Calpine Corporation,
Rosetta Resources Inc., and the other Subject Companies identified
therein.(e)
10.2 Master Transaction Agreement, dated September 7, 2005, among Calpine
Corporation, Calpine Energy Services, L.P., The Bear Stearns Companies
Inc., and such other parties as may become party thereto from time to
time. Approximately [ten] pages of this Exhibit 10.2 have been omitted
pursuant to a request for confidential treatment. The omitted language
has been filed separately with the SEC.(*)
10.3 Amendment to 1996 Stock Incentive Plan, as amended.(f)
31.1 Certification of the Chairman, President and Chief Executive Officer
Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.(*)
31.2 Certification of the Executive Vice President and Chief Financial
Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.(*)
32.1 Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.(*)
- ----------
(*) Filed herewith.
(a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q for the quarter ended June 30, 2004, filed with the SEC on August 9,
2004.
(b) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q for the quarter ended June 30, 2005, filed
with the SEC on August 9, 2005.
(c) 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.
(d) This document has been omitted in reliance on Item 601(b)(4)(iii) of
Regulation S-K. Calpine Corporation agrees to furnish a copy of such
document to the SEC upon request.
(e) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on July 13, 2005.
(f) Description of such amendment is incorporated by reference to Item 1.01 of
Calpine Corporation's Current Report on Form 8-K filed with the SEC on
September 20, 2005. Such amendment constitutes a management contract or
compensatory plan or arrangement.