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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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 March 31, 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:
538,016,014 shares of Common Stock, par value $.001 per share, outstanding
on May 9, 2005.
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CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2005
INDEX
Page
No.
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements............................................................................................ 3
Consolidated Condensed Balance Sheets March 31, 2005 and December 31, 2004...................................... 3
Consolidated Condensed Statements of Operations for the Three Months Ended March 31, 2005 and 2004.............. 5
Consolidated Condensed Statements of Cash Flows for the Three Months Ended March 31, 2005 and 2004.............. 6
Notes to Consolidated Condensed Financial Statements............................................................ 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................... 32
Item 3. Quantitative and Qualitative Disclosures About Market Risk...................................................... 58
Item 4. Controls and Procedures......................................................................................... 58
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings............................................................................................... 59
Item 6. Exhibits........................................................................................................ 59
Signatures................................................................................................................... 61
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
March 31, 2005 and December 31, 2004
March 31, December 31,
2005 2004
--------------- ---------------
(In thousands, except share and
per share amounts)
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents..................................................................... $ 812,612 $ 783,428
Accounts receivable, net...................................................................... 1,034,141 1,097,157
Margin deposits and other prepaid expense..................................................... 461,097 452,432
Inventories................................................................................... 148,770 179,395
Restricted cash............................................................................... 513,753 593,304
Current derivative assets..................................................................... 472,643 324,206
Other current assets.......................................................................... 169,068 133,643
-------------- --------------
Total current assets....................................................................... 3,612,084 3,563,565
-------------- --------------
Restricted cash, net of current portion......................................................... 194,476 157,868
Notes receivable, net of current portion........................................................ 200,443 203,680
Project development costs....................................................................... 152,407 150,179
Unconsolidated investments...................................................................... 387,639 374,032
Deferred financing costs........................................................................ 423,122 422,606
Prepaid lease, net of current portion........................................................... 431,600 424,586
Property, plant and equipment, net.............................................................. 20,712,038 20,636,394
Goodwill........................................................................................ 45,160 45,160
Other intangible assets, net.................................................................... 72,009 73,190
Long-term derivative assets..................................................................... 658,440 506,050
Other assets.................................................................................... 690,049 658,778
-------------- --------------
Total assets............................................................................... $ 27,579,467 $ 27,216,088
============== ==============
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.............................................................................. $ 945,578 $ 1,014,350
Accrued payroll and related expense........................................................... 65,555 88,719
Accrued interest payable...................................................................... 396,175 385,794
Income taxes payable.......................................................................... 79,163 82,958
Notes payable and borrowings under lines of credit, current portion........................... 209,652 204,775
Preferred interests, current portion.......................................................... 268,794 8,641
Capital lease obligation, current portion..................................................... 5,780 5,490
CCFC I financing, current portion............................................................. 3,208 3,208
Construction/project financing, current portion............................................... 100,773 93,393
Senior notes and term loans, current portion.................................................. 922,489 718,449
Current derivative liabilities................................................................ 626,125 364,965
Other current liabilities..................................................................... 287,940 314,650
-------------- --------------
Total current liabilities.................................................................. 3,911,232 3,285,392
-------------- --------------
Notes payable and borrowings under lines of credit, net of current portion...................... 682,429 769,490
Convertible debentures payable to Calpine Capital Trust III..................................... 517,500 517,500
Preferred interests, net of current portion..................................................... 493,396 497,896
Capital lease obligation, net of current portion................................................ 281,756 283,429
CCFC I financing, net of current portion........................................................ 782,020 783,542
CalGen/CCFC II financing........................................................................ 2,395,795 2,395,332
Construction/project financing, net of current portion.......................................... 2,003,443 1,905,658
Convertible Senior Notes Due 2006............................................................... 1,311 1,326
Convertible Notes Due 2014...................................................................... 623,429 620,197
Convertible Senior Notes Due 2023............................................................... 633,775 633,775
Senior notes and term loans, net of current portion............................................. 8,218,408 8,532,664
Deferred income taxes, net of current portion................................................... 925,365 1,021,739
Deferred revenue................................................................................ 116,041 114,202
Long-term derivative liabilities................................................................ 903,824 526,598
Other liabilities............................................................................... 351,389 346,230
-------------- --------------
Total liabilities.......................................................................... 22,841,113 22,234,970
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Minority interests.............................................................................. 388,499 393,445
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March 31, December 31,
2005 2004
--------------- ---------------
(In thousands, except share and
per share amounts)
(Unaudited)
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 538,017,458 shares in 2005 and 536,509,231 shares in 2004........................ 538 537
Additional paid-in capital.................................................................... 3,159,385 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............................................................................. 1,157,317 1,326,048
Accumulated other comprehensive income........................................................ 32,615 109,511
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Total stockholders' equity................................................................. $ 4,349,855 $ 4,587,673
-------------- --------------
Total liabilities and stockholders' equity................................................. $ 27,579,467 $ 27,216,088
============== ==============
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2005 and 2004
Three Months Ended
March 31,
2005 2004
-------------- -------------
(In thousands, except
per share amounts)
(Unaudited)
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue................................................................. $ 1,403,549 $ 1,245,887
Transmission sales revenue.................................................................... 3,744 5,675
Sales of purchased power for hedging and optimization......................................... 356,130 380,028
------------- -------------
Total electric generation and marketing revenue.............................................. 1,763,423 1,631,590
Oil and gas production and marketing revenue
Oil and gas sales............................................................................. 10,820 14,135
Sales of purchased gas for hedging and optimization........................................... 420,296 352,737
------------- -------------
Total oil and gas production and marketing revenue........................................... 431,116 366,872
Mark-to-market activities, net................................................................. (3,531) 12,518
Other revenue.................................................................................. 21,670 21,312
------------- -------------
Total revenue................................................................................ 2,212,678 2,032,292
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Cost of revenue:
Electric generation and marketing expense
Plant operating expense....................................................................... 195,626 172,777
Transmission purchase expense................................................................. 23,510 19,483
Royalty expense............................................................................... 10,329 5,882
Purchased power expense for hedging and optimization.......................................... 288,787 374,939
------------- -------------
Total electric generation and marketing expense.............................................. 518,252 573,081
Oil and gas operating and marketing expense
Oil and gas operating expense................................................................. 13,000 13,236
Purchased gas expense for hedging and optimization............................................ 413,259 360,487
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Total oil and gas operating and marketing expense............................................ 426,259 373,723
Fuel expense................................................................................... 921,349 789,749
Depreciation, depletion and amortization expense............................................... 143,228 129,407
Operating lease expense........................................................................ 24,777 27,799
Other cost of revenue.......................................................................... 38,171 26,380
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Total cost of revenue........................................................................ 2,072,036 1,920,139
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Gross profit............................................................................... 140,642 112,153
(Income) loss from unconsolidated investments.................................................... (6,064) (1,185)
Equipment cancellation and impairment cost....................................................... (73) 2,360
Project development expense...................................................................... 8,720 7,717
Research and development expense................................................................. 7,034 3,816
Sales, general and administrative expense........................................................ 57,137 54,328
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Income from operations......................................................................... 73,888 45,117
Interest expense................................................................................. 348,937 248,466
Interest (income)................................................................................ (14,331) (12,060)
Minority interest expense........................................................................ 10,614 8,435
(Income) from repurchase of various issuances of debt............................................ (21,772) (835)
Other expense (income), net...................................................................... 3,980 (18,425)
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Income (loss) before provision or benefit for income taxes..................................... (253,540) (180,464)
Provision (benefit) for income taxes............................................................. (84,809) (73,232)
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Income (loss) before discontinued operations................................................... (168,731) (107,232)
Discontinued operations, net of tax provision (benefit) of $-- and $(392)......................... -- 36,040
-------------- -------------
Net income (loss).......................................................................... $ (168,731) $ (71,192)
============= =============
Basic and diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding............................................ 447,599 415,308
Income (loss) before discontinued operations................................................... $ (0.38) $ (0.26)
Discontinued operations, net of tax............................................................ -- 0.09
-------------- -------------
Net income (loss).......................................................................... $ (0.38) $ (0.17)
============= =============
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
Three Months Ended
March 31,
--------------------------------
2005 2004
--------------- ---------------
(In thousands)
(Unaudited)
Cash flows from operating activities:
Net loss........................................................................................ $ (168,731) $ (71,192)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization (1).................................................. 206,810 197,183
Deferred income taxes, net.................................................................... (84,809) (97,550)
Loss (gain) on sale of assets................................................................. 1,004 (32,211)
Stock compensation expense.................................................................... 7,136 4,266
Foreign exchange (gains) losses............................................................... (5,240) (9,984)
Change in net derivative assets and liabilities............................................... 24,487 (36,230)
(Income) from unconsolidated investments...................................................... (6,064) (2,506)
Distributions from unconsolidated investments................................................. 4,872 5,140
Other......................................................................................... (11,231) 7,599
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable........................................................................... 61,092 (23,339)
Other current assets.......................................................................... 15,740 (49,708)
Other assets.................................................................................. (39,243) (6,823)
Accounts payable and accrued expense.......................................................... (86,745) 1,981
Other liabilities............................................................................. (33,670) (59,856)
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Net cash used in operating activities........................................................ (114,592) (173,230)
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Cash flows from investing activities:
Purchases of property, plant and equipment...................................................... (257,299) (414,945)
Disposals of property, plant and equipment...................................................... 299 176,914
Acquisitions, net of cash acquired.............................................................. -- (187,466)
Advances to unconsolidated investments.......................................................... -- (479)
Project development costs....................................................................... (3,762) (6,837)
Decrease in restricted cash..................................................................... 42,943 346,338
Decrease in notes receivable.................................................................... 389 1,772
Other........................................................................................... (3,418) 13,332
-------------- --------------
Net cash used in investing activities.......................................................... (220,848) (71,371)
-------------- --------------
Cash flows from financing activities:
Borrowings from notes payable and borrowings under lines of credit.............................. 3,509 2,394,565
Repayments of notes payable and borrowings under lines of credit................................ (89,005) (86,783)
Borrowings from project financing............................................................... 144,704 315,142
Repayments of project financing................................................................. (41,654) (2,343,403)
Repayments and repurchases of senior notes...................................................... (61,197) (14,759)
Repurchase of convertible senior notes.......................................................... (15) (586,926)
Proceeds from issuance of 4.75% convertible senior notes........................................ -- 250,000
Proceeds from preferred interests (2)........................................................... 260,000 --
Proceeds from prepaid commodity contract (3).................................................... 213,081 --
Financing and transaction costs................................................................. (47,851) (75,727)
Other........................................................................................... (12,862) (12,200)
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Net cash provided by (used in) financing activities............................................ 368,710 (160,091)
-------------- --------------
Effect of exchange rate changes on cash and cash equivalents...................................... (4,086) (4,310)
Net increase (decrease) in cash and cash equivalents.............................................. 29,184 (409,002)
Cash and cash equivalents, beginning of period.................................................... 783,428 991,806
-------------- --------------
Cash and cash equivalents, end of period.......................................................... $ 812,612 $ 582,804
============== ==============
Cash paid during the period for:
Interest, net of amounts capitalized............................................................ $ 299,699 $ 238,954
Income taxes.................................................................................... $ 8,200 $ 15,361
- ----------
<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) For a discussion of the $260.0 million offering of Redeemable Preferred
Securities see Note 6 of the accompanying notes.
(3) For a discussion of the Deer Park Energy Center prepaid commodity contract,
see Note 8 of the accompanying notes.
</FN>
Schedule of non-cash investing and financing activities:
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.
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
March 31, 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 in the United States of America, Canada, and the United Kingdom. The
Company is involved in the development, construction, ownership and operation of
power generation facilities and the sale of electricity and its by-product,
thermal energy, primarily in the form of steam. The Company has ownership
interests in, and operates, gas-fired power generation and cogeneration
facilities, gas fields, gathering systems and gas pipelines, geothermal steam
fields and geothermal power generation facilities in the United States of
America. In Canada, the Company has ownership interests in, and operates,
gas-fired power generation facilities. In Mexico, Calpine is a joint venture
participant in a gas-fired power generation facility under construction. In the
United Kingdom, the Company owns and operates a gas-fired power cogeneration
facility. 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.
Gas produced, and not physically delivered to the Company's generating plants,
is sold to third parties. 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
operations and maintenance ("O&M") services.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying unaudited interim
Consolidated Condensed Financial Statements of the Company have been prepared by
the Company pursuant to the rules and regulations of the Securities and Exchange
Commission. In the opinion of management, the Consolidated Condensed Financial
Statements include the adjustments necessary to present fairly the information
required to be set forth therein. Certain information and note disclosures
normally included in financial statements prepared in accordance with generally
accepted accounting principles in the United States of America have been
condensed or omitted from these statements pursuant to such rules and
regulations and, accordingly, these financial statements should be read in
conjunction with the audited Consolidated Financial Statements of the Company
for the year ended December 31, 2004, included in the Company's Annual Report on
Form 10-K. The results for interim periods are not necessarily indicative of the
results for the entire year.
Reclassifications -- Certain prior years' amounts in the Consolidated
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 2004 amounts have
also been restated for discontinued operations. See Note 7 for more information.
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, primary beneficiary determination for the Company's
investments in variable interest entities ("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.
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
subsidiaries is limited to the operations of the respective projects. At March
31, 2005 and December 31, 2004, $254.0 million and $191.0 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 March 31,
2005 and 2004, $115.6 million and $192.3 million of the Company's cash and cash
equivalents was held in bank accounts outside the United States for the same
periods, respectively.
Accounting for Commodity Contracts -- Commodity contracts are evaluated to
determine whether the contract is: (1) accounted for as a lease, (2) accounted
for as a derivative or (3) accounted for as an executory contract and
additionally whether the financial statement presentation is gross or net.
Leases -- Commodity contracts are evaluated for lease accounting in
accordance with SFAS No. 13, "Accounting for Leases," ("SFAS No. 13") and
Emerging Issues Task Force ("EITF") Issue No. 01-08, "Determining Whether an
Arrangement Contains a Lease," ("EITF Issue No. 01-08"). EITF Issue No. 01-08
clarifies the requirements of identifying whether an arrangement should be
accounted for as a lease at its inception. The guidance in the consensus is
designed to broaden the scope of arrangements, such as power purchase agreements
("PPA"), accounted for as leases. EITF Issue No. 01-08 requires both parties to
an arrangement to determine whether a service contract or similar arrangement
is, or includes, a lease within the scope of SFAS No. 13. The consensus is being
applied prospectively to arrangements agreed to, modified, or acquired in
business combinations on or after July 1, 2003. Prior to adopting EITF Issue No.
01-08, the Company had accounted for certain contractual arrangements as leases
under existing industry practices, and the adoption of EITF Issue No. 01-08 did
not materially change the Company's accounting for leases. Under the guidance of
SFAS No. 13, operating leases with minimum lease rentals which vary over time
must be levelized over the term of the contract. The Company currently levelizes
these contracts on a straight-line basis. Prepaid lease expense (the excess of
lease payments made over the levelized expense recognized) totaled $433.7
million and $426.7 million at March 31, 2005 and December 31, 2004,
respectively, which is recorded in the Company's Consolidated Condensed Balance
Sheets within "Other current assets" and as "Prepaid Lease, net of current
portion." For income statement presentation purposes, income from PPAs accounted
for as leases is classified within "Electricity and steam revenue" in the
Company's Consolidated Condensed Statements of Operations.
Effective Tax Rate -- For the three months ended March 31, 2005, the
effective rate decreased to 33% as compared to 41% for the three months ended
March 31, 2004. The tax rate on continuing operations for the quarter ended
March 31, 2004, has been restated to reflect the reclassification to
discontinued operations of certain tax expense (benefit) related to the sale of
oil and gas reserves. See Note 7 of the Notes to Consolidated Condensed
Financial Statements. This effective rate variance is due to 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,"
("SFAS No. 150") 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.
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 as amended by SFAS No. 148. SFAS No. 148
amends SFAS No. 123 to provide alternative methods of transition for companies
that voluntarily change their accounting for stock-based compensation from the
less preferred intrinsic value based method to the more preferred fair value
based method. Prior to its amendment, SFAS No. 123 required that companies
enacting a voluntary change in accounting principle from the intrinsic value
methodology provided by APB Opinion No. 25 could only do so on a prospective
basis; no adoption or transition provisions were established to allow for a
restatement of prior period financial statements. SFAS No. 148 provides two
additional transition options to report the change in accounting principle --
the modified prospective method and the retroactive restatement method.
Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to
require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The Company 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 if SFAS No.
123 accounting had been applied to all prior periods presented within its
financial statements. The adoption of SFAS No. 123 has had a material impact on
the Company's financial statements. The table below reflects the pro forma
impact of stock-based compensation on the Company's net loss and loss per share
for the three months ended March 31, 2005 and 2004, had the Company applied the
accounting provisions of SFAS No. 123 to its financial statements in years prior
to adoption of SFAS No. 123 on January 1, 2003 (in thousands, except per share
amounts):
Three Months Ended March 31,
----------------------------
-------------- -------------
2005 2004
------------- -------------
Net loss
As reported............................................................................. $ (168,731) $ (71,192)
Pro Forma............................................................................... (169,252) (72,839)
Loss per share data:
Basic and diluted loss per share
As reported............................................................................. $ (0.38) $ (0.17)
Pro Forma............................................................................... (0.38) (0.18)
Stock-based compensation cost included in net loss, as reported............................ $ 4,659 $ 2,581
Stock-based compensation cost included in net loss, pro forma.............................. 5,180 4,228
New Accounting Pronouncements
SFAS No. 123-R
In December 2004, FASB issued SFAS No. 123 (revised 2004) ("SFAS No.
123-R"), "Share Based Payments." This Statement revises SFAS No. 123,
"Accounting for Stock-Based Compensation" ("SFAS No. 123") and supersedes
Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued
to Employees" ("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 period during which an employee is required to provide service in exchange
for the award -- the requisite service period (usually the vesting period). 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.
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 or financial
position to be materially affected upon adoption of SFAS No. 123-R.
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 this
Statement using a modified version of prospective application (modified
prospective application). Under modified prospective application, compensation
cost for the portion of awards for which the employee's requisite service has
not been rendered that 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 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," ("SFAS
No. 148") 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" ("SFAS No.
128") 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
Senior Notes and 2014 Convertible Notes contain provisions that would require
share settlement in the event of conversion under certain limited events of
default, including bankruptcy. Additionally, the 2023 Convertible Senior Notes
include a provision allowing the Company to meet a put with either cash or
shares of stock. The revised guidance, if not amended before final issuance,
would increase the potential dilution to the Company's EPS, particularly when
the price of the Company's common stock is low, since the more dilutive of
calculations would be used considering both:
o normal conversion assuming a combination of cash and variable number of
shares; and
o conversion during certain limited events of default assuming 100% shares at
the fixed conversion rate, or, in the case 2023 Convertible Senior 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" ("SFAS No. 151"). 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, this Statement 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 is not expected to 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," ("SFAS No. 153"). This standard eliminates the exception in APB Opinion
No. 29, "Accounting for Nonmonetary Transactions" ("APB Opinion No. 29") 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 standard 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" ("SFAS No. 66"), 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 is not
expected to materially impact the Company's consolidated results of operations,
cash flows or financial position.
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"). This Issue 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 considered the model outlined in EITF Issue No. 03-13 in
its evaluation of the September 2004 sale of the Canadian and Rockies oil and
gas reserves (see Note 7 for more information). The final consensus did not
change the Company's original conclusions reached under the existing
discontinued operations guidance in SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets," ("SFAS No. 144").
3. Available-for-Sale Debt Securities
On September 30, 2004, the Company repurchased par value of $115.0 million
HIGH TIDES III for cash of $111.6 million. Due to the deconsolidation of the
Trusts upon the adoption of FIN 46 as of December 31, 2003, and the terms of the
underlying debentures, the repurchased HIGH TIDES III could not be offset
against the convertible subordinated debentures and are accounted for as
available-for-sale securities and recorded in the Consolidated Condensed Balance
Sheets within "Other assets" at fair market value at March 31, 2005, with the
difference from their repurchase price recorded in OCI (in thousands):
Gross
Unrealized
Gains in Other
Repurchase Comprehensive
Price (1) Income Fair Value
---------- -------------- ---------------------------------
March 31, 2005 December 31, 2004
-------------- -----------------
HIGH TIDES III... $ 110,592 $ 2,108 $ 112,700 $ 111,550
- ----------
(1) The repurchase price is shown net of accrued interest. The repurchased
amount was $111.6 million less $1.0 million of accrued interest.
4. Property, Plant and Equipment, Net and Capitalized Interest
As of March 31, 2005, and December 31, 2004, the components of property,
plant and equipment, net, are stated at cost less accumulated depreciation and
depletion as follows (in thousands):
March 31, December 31,
2005 2004
-------------- --------------
Buildings, machinery, and equipment.............. $ 16,439,297 $ 16,449,029
Oil and gas properties, including pipelines...... 1,206,725 1,189,626
Geothermal properties............................ 475,053 474,869
Other............................................ 220,413 218,177
------------- -------------
18,341,488 18,331,701
Less: accumulated depreciation and depletion..... (2,262,837) (2,122,371)
------------- -------------
16,078,651 16,209,330
Land............................................. 105,417 105,087
Construction in progress......................... 4,527,970 4,321,977
------------- -------------
Property, plant and equipment, net............... $ 20,712,038 $ 20,636,394
============= =============
Capital Spending -- Construction and Development
Construction and Development costs in process consisted of the following at
March 31, 2005 (in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP CIP Costs Equipment
-------- ------------- ------------- ------------- -------------
Projects in active construction (1)............. 7 $ 2,246,703 $ 702,484 $ -- $ --
Projects in suspended construction.............. 3 1,137,452 396,248 -- --
Projects in advanced development................ 11 690,774 520,036 105,727 --
Projects in suspended development............... 6 419,105 168,985 37,728 --
Projects in early development................... 2 -- -- 8,952 --
Other capital projects.......................... NA 33,936 -- -- --
Unassigned equipment............................ NA -- -- -- 66,161
------------- ------------- ------------- -------------
Total construction and development costs...... $ 4,527,970 $ 1,787,753 $ 152,407 $ 66,161
============= ============= ============= =============
- ----------
<FN>
(1) There are a total of eight projects in active construction. This includes
the seven projects that are recorded in CIP in the table above and one
project that is recorded in unconsolidated investments.
</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 seven projects in active
construction are projected to come on line from May 2005 to November 2007. These
projects will bring on line approximately 2,878 MW of base load capacity (3,210
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 March 31, 2005, the total projected costs to complete these
projects is $843.7 million and the estimated funding requirements to complete
these projects, net of expected project financing proceeds, is approximately
$48.3 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 will bring on line
approximately 1,769 MW of base load capacity (2,035 MW with peaking capacity).
The Company expects to finance the remaining $340.8 million projected costs to
complete these projects.
Projects in Advanced Development -- There are eleven projects in advanced
development. These projects will bring on line approximately 5,072 MW of base
load capacity (6,150 MW with peaking capacity). Interest and other costs related
to the development activities necessary to bring these projects to their
intended use are being capitalized. However, the capitalization of interest has
been suspended on four projects for which development activities are
substantially complete but construction will not commence until a PPA and
financing are obtained. The estimated cost to complete the eleven projects in
advanced development is approximately $3.1 billion. The Company's current plan
is to finance these project costs as PPAs are arranged.
Suspended Development Projects -- Due to current electric market
conditions, we have ceased capitalization of additional development costs and
interest expense on six development projects on which work has been suspended.
Capitalization of costs may recommence as work on these projects resumes, if
certain milestones and criteria are met indicating that it is again highly
probable that the costs will be recovered through future operations. As is true
for all 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. These projects would bring on line approximately 2,956 MW of base load
capacity (3,409 MW with peaking capacity). The estimated cost to complete these
projects is approximately $1.8 billion.
Projects in Early Development -- Costs for projects that are in early
stages of development are capitalized only when it is highly probable that such
costs are ultimately recoverable and significant project milestones are
achieved. Until then all costs, including interest costs, are expensed. The
projects in early development with capitalized costs relate to two projects and
include geothermal drilling costs and equipment purchases.
Other Capital Projects -- Other capital projects primarily consist of
enhancements to operating power plants, oil and gas and geothermal resource and
facilities development, as well as software developed for internal use.
Unassigned Equipment -- As of March 31, 2005, the Company had made progress
payments on four turbines and other equipment with an aggregate carrying value
of $66.2 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," ("SFAS No. 34") as amended by SFAS No. 58, "Capitalization of Interest
Cost in Financial Statements That Include Investments Accounted for by the
Equity Method (an Amendment of FASB Statement No. 34)." The Company's qualifying
assets include CIP, certain oil and gas properties under development,
construction costs related to unconsolidated investments in power projects under
construction, advanced stage development costs, as well as such above mentioned
assets classified as held for sale. For the three months ended March 31, 2005
and 2004, the total amount of interest capitalized was $70.4 million, and $108.5
million, including $10.7 million and $18.5 million, respectively, of interest
incurred on funds borrowed for specific construction projects and $59.7 million
and $90.0 million, respectively, of interest incurred on general corporate funds
used for the advanced stages of development and 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 months ended
March 31, 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
calculation of interest incurred on general corporate funds are the Company's
Senior Notes and term loans as well as the secured working capital revolving
credit facility.
Impairment Evaluation -- All construction and development projects and
unassigned turbines are reviewed for impairment whenever there is an indication
of potential reduction in fair value. Equipment assigned to such projects is not
evaluated for impairment separately, as it is integral to the assumed future
operations of the project to which it is assigned. If it is determined that it
is no longer probable that the projects will be completed and all capitalized
costs recovered through future operations, the carrying values of the projects
would be written down to the recoverable value in accordance with the provisions
of SFAS No. 144. 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 quarter ended March 31, 2004, the Company recorded to the
"Equipment cancellation and impairment cost" line of the Consolidated Condensed
Statement of Operations $2.4 million 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.
5. Unconsolidated Investments
The Company's unconsolidated investments are integral to its operations.
The Company's joint venture investments were evaluated under FASB-issued
Interpretation No. 46 "Consolidation of Variable Interest Entities - An
Interpretation of ARB 51" ("FIN 46") to determine which, if any, entities were
VIEs. Based on this evaluation, the Company determined that the Acadia Power
Partners, LLC, Valladolid III Energy Center, Grays Ferry Cogeneration
Partnership, Whitby Cogeneration Limited Partnership and Androscoggin Energy LLC
were VIEs, in which the Company held a significant variable interest. However,
all of the entities except for Acadia Power Partners, LLC 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 Power Partners, LLC, 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 the Androscoggin Energy Center as discussed below.
Acadia Power Partners, LLC ("Acadia PP") is the owner of a 1,210-megawatt
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 March 31, 2005, is limited to the book value of its investment of
approximately $216.5 million, plus any loss that may accrue from a tolling
agreement between Acadia and Calpine Energy Services, L.P. ("CES").
Valladolid III Energy Center is the owner of a 525-megawatt, natural
gas-fired energy center currently under construction at Valladolid, Mexico in
the Yucatan Peninsula. The facility will deliver electricity to Comision Federal
de Electricidad ("CFE") under a 25-year power sales agreement. The project is a
joint venture between the Company, Mitsui & Co., Ltd., ("Mitsui") and Chubu
Electric ("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 March 31, 2005, is limited
to the book value of its investment of approximately $82.2 million.
Grays Ferry Cogeneration Partnership ("Grays Ferry") is the owner of a
175-megawatt gas-fired cogeneration facility, Grays Ferry Power Plant, located
in Pennsylvania and is a joint venture between the Company and Trigen-Schuylkill
Cogeneration, Inc. The Company's involvement in this VIE began with its
acquisition of the independent power producer, Cogeneration Corporation of
America, Inc. ("Cogen America"), now called Calpine Cogen, in December 1999. The
Grays Ferry joint venture project was part of the portfolio of assets owned by
Cogen America. The Company's maximum potential exposure to loss at March 31,
2005, is limited to the book value of its investment of approximately $49.4
million.
Whitby Cogeneration Limited Partnership ("Whitby") is the owner of a
50-megawatt gas-fired cogeneration facility, Whitby Cogeneration, located in
Ontario, Canada and is a joint venture between the Company and a privately held
enterprise. The Company's involvement in this VIE began with its acquisition of
a portfolio of assets from Westcoast Energy Inc. ("Westcoast") in September
2001, which included the Whitby joint venture project. The Company's maximum
potential exposure to loss at March 31, 2005, is limited to the book value of
its investment of approximately $38.4 million.
Androscoggin Energy LLC ("AELLC") is the owner of a 136-megawatt gas-fired
cogeneration facility, Androscoggin Energy Center, located in Maine and is a
joint venture between the Company, and affiliates of Wisvest Corporation and
International Paper Company ("IP"). The Company's involvement in this VIE began
with its acquisition of the independent power producer, SkyGen Energy LLC
("SkyGen") in October 2000. The AELLC project was part of the portfolio of
assets owned by SkyGen. The facility had construction debt of $59.6 million and
$60.3 million outstanding as of March 31, 2005, and December 31, 2004,
respectively. The debt is non- recourse to Calpine Corporation. On November 3,
2004, a jury verdict was rendered against AELLC in a breach of contract dispute
with IP. See Note 11 for more information about the legal proceeding. 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 reserve. See Note 14 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 --------------------------
March 31, March 31, December 31,
2005 2005 2004
------------ ----------- -------------
Acadia Energy Center................ 50.0% $ 216,524 $ 214,501
Valladolid III Energy Center........ 45.0% 82,244 77,401
Grays Ferry Power Plant............. 50.0% 49,350 48,558
Whitby Cogeneration (1)............. 15.0% 38,448 32,528
Androscoggin Energy Center (2)...... 32.3% -- --
Other............................... -- 1,073 1,044
----------- ----------
Total unconsolidated investments.. $ 387,639 $ 374,032
=========== ==========
- ----------
(1) Whitby is owned 50% by the Company but a 70% economic share in the
Company's ownership interest has been effectively transferred to Calpine
Power, LP ("CPLP") through a loan from CPLP to the Company's entity which
holds the investment interest in Whitby.
(2) Excludes certain Notes Receivable.
On September 2, 2004, the Company completed the sale of its equity
investment in the Calpine Natural Gas Trust ("CNGT"). In accordance with SFAS
No. 144 the Company's 25 percent equity method investment in the CNGT was
considered part of the larger disposal group and therefore evaluated and
accounted for as a discontinued operation. Accordingly, the Company made
reclassifications to current and prior period financial statements to reflect
the sale or designation as "held for sale" of the CNGT investment balance and to
separately classify the income from the unconsolidated investment as well as the
gain on sale of the investment from operating results of continuing operations
to discontinued operations. The tables below for distributions from investments
and related party transactions with unconsolidated investments include CNGT
through the date of sale, September 2, 2004. See Note 7 for more information on
the sale of the Canadian natural gas reserves and petroleum assets.
The third party debt on the books of the unconsolidated investments is not
reflected on the Company's balance sheet. At March 31, 2005, and December 31,
2004, third party investee debt was approximately $220.3 million and $130.8
million, respectively. Of these amounts, $59.6 million and $60.3 million,
respectively, relates to the Company's investment in AELLC, for which the cost
method of accounting was used as of December 31, 2004. Based on the Company's
pro rata ownership share of each of the investments, the Company's share would
be approximately $86.2 million and $45.6 million for the respective periods.
These amounts include the Company's share for AELLC of $19.2 million and $19.5
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 Three Months Ended March 31,
----------------------------------------------
2005 2004 2005 2004
---------- ---------- -------- --------
Acadia Energy Center......................................... $ 4,798 $ 5,217 $ 2,776 $ 2,193
Aries Power Plant............................................ -- (1,589) -- --
Grays Ferry Power Plant...................................... 306 (1,851) -- --
Whitby Cogeneration.......................................... 906 317 2,017 565
Calpine Natural Gas Trust.................................... -- -- -- 2,313
Androscoggin Energy Center................................... -- (1,252) -- --
Other........................................................ 54 109 79 69
---------- ---------- -------- --------
Total..................................................... $ 6,064 $ 951 $ 4,872 $ 5,140
========== ========== ======== ========
Interest income on notes receivable from power projects (1).. $ -- $ 234
---------- ----------
Total..................................................... $ 6,064 $ 1,185
========== ==========
- ----------
<FN>
The Company provides for deferred taxes on its share of earnings.
(1) At March 31, 2005, and December 31, 2004, notes receivable from power
projects represented an outstanding loan to the Company's investment,
AELLC, in the amounts of $4.0 million and $4.0 million after impairment
reserves, respectively. See the discussion of this investment above.
</FN>
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.
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 March 31, 2005 and December 31, 2004,
reflected in the accompanying Consolidated Condensed Balance Sheets, and the
related party transactions for the three months ended March 31, 2005, and 2004,
reflected in the accompanying Consolidated Condensed Statements of Operations
are summarized as follows (in thousands):
March 31, December 31,
2005 2004
---------- ------------
Accounts receivable................................ $ 372 $ 765
Accounts payable................................... 8,800 ,489
Note receivable.................................... 4,037 4,037
Other receivables.................................. 415 --
2005 2004
--------- --------------
For the Three Months Ended March 31,
Revenue............................................ $ 34 $ 786
Cost of revenue.................................... 35,189 32,746
Interest income.................................... -- 234
Gain on sale of assets............................. -- 6,240
6. Debt
On January 28, 2005, the Company's indirect subsidiary Metcalf Energy
Center, LLC ("Metcalf") obtained a $100.0 million, non-recourse credit facility
for the Metcalf Energy Center in San Jose, CA. Loans extended to Metcalf under
the facility will fund the balance of construction activities for the
602-megawatt, natural gas-fired power plant. The project finance facility will
mature in July 2008. As of March 31, 2005, the Company had $15.5 million
outstanding under this credit facility.
On January 31, 2005, the Company's indirect subsidiary, Calpine European
Funding (Jersey) Limited ("Calpine Jersey II"), received funding on a $260.0
million offering of Redeemable Preferred Shares, due on July 30, 2005. The
shares were offered in a private placement in the United States under Regulation
D under the Securities Act of 1933 and outside of the United States pursuant to
Regulation S under the Securities Act of 1933. The Redeemable Preferred Shares
priced at U.S. LIBOR plus 850 basis points, were offered at 99% of par. The
proceeds from the offering of the shares must be used in accordance with the
provisions of the Company's existing bond indentures. See "Indenture Compliance"
below for a further discussion.
On March 1, 2005, our indirect subsidiary, Calpine Steamboat Holdings, LLC,
closed on a $503.0 million non-recourse project finance facility that will
provide $466.5 million to complete the construction of the Mankato Energy Center
("Mankato") in Blue Earth County, Minnesota, and the Freeport Energy Center
("Freeport") in Freeport, Texas. The remaining $36.5 million of the facility
provides a letter of credit for Mankato that is required to serve as collateral
available to Northern States Power Company if Mankato does not meet its
obligations under the PPA. The project finance facility will initially be
structured as a construction loan, converting to a term loan upon commercial
operations of the plants, and will mature in December 2011. The facility will
initially be priced at LIBOR plus 1.75%. As of March 31, 2005, the Company had
$48.0 million and $54.7 million outstanding for Mankato and Freeport,
respectively, under this project finance facility.
During the three months ended March 31, 2005, the Company repurchased $31.8
million in principal amount of its outstanding 8 1/2% Senior Notes Due 2011 in
exchange for $23.0 million in cash plus accrued interest. The Company also
repurchased $48.7 million in principal amount of its outstanding 8 5/8% Senior
Notes Due 2010 in exchange for $35.0 million in cash plus accrued interest. The
Company recorded a pre-tax gain on these transactions in the amount of $21.8
million after write-offs of unamortized deferred financing costs and the
unamortized discounts.
Annual Debt Maturities -- The annual principal repayments or maturities of
notes payable and borrowings under lines of credit, convertible debentures
payable to Calpine Capital Trust III, preferred interests, capital lease
obligation, CCFC I financing, CalGen/CCFC II financing, construction/project
financing, convertible senior notes, and senior notes and term loans, as of
March 31, 2005, are as follows (in thousands):
April through December 2005...... $ 1,199,063
2006............................. 1,122,490
2007............................. 1,852,520
2008............................. 2,229,105
2009............................. 1,666,923
Thereafter....................... 10,302,845
--------------
Total debt....................... 18,372,946
(Discount) / Premium............. (228,988)
--------------
Total.......................... $ 18,143,958
==============
The total current debt obligation as of March 31, 2005, was $1,510.7
million, which consisted of $1,199.1 million of April through December 2005
repayments or maturities and $311.6 million of the $1,122.5 million 2006
repayments or maturities.
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:
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 and, consequently, the Company 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 the Company's subsidiaries for purposes of
financing certain types of capital expenditures, including plant development,
construction and acquisition expenses. In addition, if and so long as the
Company's interest coverage ratio is below 2:1, the Company's ability to invest
in unrestricted subsidiaries and non-subsidiary affiliates and make certain
other types of restricted payments will be limited. As of March 31, 2005, the
Company's interest coverage ratio (as so defined) has fallen below 1.75:1 and,
until the ratio is greater than 1.75:1, certain of the Company's indentures will
prohibit any further investments in non-subsidiary affiliates.
Certain of the Company's indebtedness issued in the last half of 2004 was
permitted under the Company's indentures on the basis that the proceeds would be
used to repurchase or redeem existing indebtedness. While the Company completed
a portion of such repurchases during the fourth quarter of 2004 and the first
quarter of 2005, the Company is still in the process of completing the required
amount of repurchases. While the amount of indebtedness that must still be
repurchased will ultimately depend on the market price of the Company's
outstanding indebtedness at the time the indebtedness is repurchased, based on
current market conditions, the Company estimates that, as of March 31, 2005, as
adjusted for market conditions and financial covenant calculations, the Company
would be required to spend approximately $294.0 million in order to fully
satisfy this requirement. This amount has been classified as Senior Notes,
current portion, on the Company's Consolidated Condensed Balance Sheet.
Subsequent to March 31, 2005, the Company has satisfied a portion of such
requirement. See Note 14.
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 or to
repurchase or repay certain types of subsidiary indebtedness, in each case
within 365 days of the closing date of the transaction. In light of this
requirement, and taking into account the amount of capital expenditures
currently budgeted for 2005, the Company anticipates that subsequent to March
31, 2005, it will need to use approximately $250.0 of the net proceeds of the
$360.0 million Two-Year Redeemable Preferred Shares issued by its Calpine
(Jersey) Limited ("Calpine Jersey I") subsidiary on October 26, 2004, and
approximately $180.0 million of the net proceeds of the $260.0 million
Redeemable Preferred Shares issued by its Calpine Jersey II on January 31, 2005,
to repurchase or repay certain subsidiary indebtedness. Accordingly, $430.0
million of long-term debt has been reclassified as Senior Notes, current
portion, on the Company's Consolidated Condensed Balance Sheet. The actual
amount of the net proceeds that will be required to be used to repurchase or
repay subsidiary debt will depend upon the actual amount of the net proceeds
that is used to make capital expenditures, which may be more or less than the
amount currently budgeted.
As noted above, the Company has significant debt maturities or bond
purchase requirements in 2005 as well as significant debt maturities in 2006 and
beyond. During the first quarter of 2005, the Company's cash flow from
operations used $114.6 million and at March 31, 2005, the Company had negative
working capital of $299.1 million. In addition, as noted in Note 11, certain
bond holders have raised issues concerning the use of proceeds from certain of
the planned or recently executed transactions.
In addition, 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 over the near term as the Company's cash requirements (including the
Company's refinancing obligations) are expected to exceed the Company's
unrestricted cash on hand and cash from operations. Accordingly, the Company has
in place a liquidity-enhancing program which includes possible sales or
monetizations of certain of the Company's assets, and whether the Company will
have sufficient liquidity will depend on the success of that program. No
assurance can be given that the Company's liquidity-enhancing program will be
successful. Even if the Company's liquidity-enhancing program is successful,
there can be no assurance that the Company will continue its construction
program without suspending further construction or development work on one or
more projects and possibly incurring substantial impairment losses as a result.
For further discussion of this see the risk factors in our 2004 Form 10-K. See
below for progress achieved in the Company's liquidity program during the three
months ended March 31, 2005. On March 31, 2005, the Company's cash and cash
equivalents on hand totaled $0.8 billion (see Note 2), and the current portion
of restricted cash totaled approximately $0.5 billion.
Calpine has guaranteed the payment of a portion of the rents due under the
lease of the Greenleaf generating facilities in California. This lease is
between an owner trustee acting on behalf of Union Bank of California, as
lessor, and a Calpine subsidiary, Calpine Greenleaf, Inc., as lessee. Calpine
does not currently meet the requirements of a financial covenant contained in
the guarantee agreement. The lessor has waived this non-compliance through May
15, 2005, and Calpine is currently in discussions with the lessor to modify the
lease, Calpine's guarantee thereof, and other related documents so as to
eliminate the covenant in question. In the event the lessor's waiver were to
expire prior to completion of this amendment, the lessor could at that time
elect to accelerate the payment of certain amounts owing under the lease,
totaling approximately $16.0 million. In the event the lessor were to elect to
require Calpine to make this payment, the lessor's remedy under the guarantee
and the lease would be limited to taking steps to collect damages from Calpine;
the lessor would not be entitled to terminate or exercise other remedies under
the Greenleaf lease.
In connection with several of our subsidiaries' lease financing
transactions (Agnews, Geysers, Greenleaf, Pasadena, Rumford/Tiverton, 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 the Company's waiver request so long as the required insurance coverage is
not reasonably available or commercially feasible and we deliver a report 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.
Unrestricted Subsidiaries -- The information in this paragraph is required
to be provided under the terms of the indentures and credit agreement governing
the various tranches of the Company's second-priority secured indebtedness
(collectively, the "Second Priority Secured Debt Instruments"). The Company has
designated certain of its subsidiaries as "unrestricted subsidiaries" under the
Second Priority Secured Debt Instruments. A subsidiary with "unrestricted"
status thereunder generally is not required to comply with the covenants
contained therein that are applicable to "restricted subsidiaries." The Company
has designated Calpine Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy
Cogen, L.P. as "unrestricted subsidiaries" for purposes of the Second Priority
Secured Debt Instruments.
7. 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.
Oil and Gas Production and Marketing
On September 1, 2004, the Company along with Calpine Natural Gas L.P., a
Delaware limited partnership, completed the sale of its Rocky Mountain gas
reserves that were primarily concentrated in two geographic areas: the Colorado
Piceance Basin and the New Mexico San Juan Basin. Together, these assets
represented approximately 120 billion cubic feet equivalent ("Bcfe") of proved
gas reserves, producing approximately 16.3 million net cubic feet equivalent
("Mmcfe") per day of gas. Under the terms of the agreement Calpine received 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 the CNGT. In accordance with SFAS No. 144 the Company's 25% equity
method investment in the CNGT was considered part of the larger disposal group
(i.e., assets to be disposed of together as a group in a single transaction to
the same buyer), and therefore evaluated and accounted for as discontinued
operations. Under the terms of the agreement, Calpine received cash payments of
approximately Cdn$808.1 million, or approximately US$626.4 million. Calpine
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.
In connection with the sale of the oil and gas assets in Canada, the
Company entered into a seven-year gas purchase agreement beginning on March 31,
2005, and expiring on October 31, 2011, that allows, but does not require, the
Company to purchase gas from the buyer at current market index prices. The
agreement is not asset specific and can be settled by any production that the
buyer has available.
In connection with the sale of the Rocky Mountain gas reserves, the New
Mexico San Juan Basin sales agreement allows for the buyer and the Company to
execute a ten-year gas purchase agreement for 100% of the underlying gas
production of sold reserves, at market index prices. Any agreement would be
subject to mutually agreeable collateral requirements and other customary terms
and provisions. As of October 1, 2004, the gas purchase agreement was finalized
and executed between the Company and the buyer.
The Company believes that all final terms of the gas purchase agreements
described above, are on a market value and arm's length basis. If the Company
elects in the future to exercise a call option over production from the disposed
components, the Company will consider the call obligation to have been met as if
the actual production delivered to the Company under the call was from assets
other than those constituting the disposed components.
Electric Generation and Marketing
On January 15, 2004, the Company completed the sale of its 50-percent
undivided interest in the 545 megawatt Lost Pines 1 Power Project to GenTex
Power Corporation, an affiliate of the Lower Colorado River Authority (LCRA).
Under the terms of the agreement, Calpine received a cash payment of $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 megawatts of electricity through December 31, 2004. At December 31, 2003,
the Company's undivided interest in the Lost Pines facility was classified as
"held for sale."
Summary
The Company made reclassifications to current and prior period financial
statements to reflect the sale of these oil and gas and power plant assets and
liabilities and to separately classify the operating results of the assets sold
and gain on sale of those assets from the operating results of continuing
operations to discontinued operations.
The table below presents significant components of the Company's income
from discontinued operations for the three months ended March 31, 2004, (in
thousands). The Company had no corresponding income from discontinued operations
for the three months ended March 31, 2005, and no assets held for sale as of
March 31, 20005.
Three Months Ended March 31, 2004
--------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- --------- --------
Total revenue ............................ $ 2,679 $ 10,446 $ -- $ 13,125
======== ======== ========= ========
Gain on disposal before taxes ............ $ 35,326 $ -- $ -- $ 35,326
Operating income (loss) from
discontinued operations before taxes ... (145) 467 -- 322
-------- -------- --------- --------
Income from discontinued operations
before taxes ........................... $ 35,181 $ 467 $ -- $ 35,648
Income tax provision (benefit) ........... 12,324 (12,716) $ -- $ (392)
-------- -------- --------- --------
Income from discontinued operations,
net of tax ............................. $ 22,857 $ 13,183 $ -- $ 36,040
======== ======== ========= ========
8. Derivative Instruments
Summary of Derivative Values
The table below reflects the amounts that are recorded as assets and
liabilities at March 31, 2005, for the Company's derivative instruments (in
thousands):
Commodity
Interest Rate Derivative Total
Derivative Instruments Derivative
Instruments Net Instruments
------------- ------------- -------------
Current derivative assets.......... $ -- $ 472,643 $ 472,643
Long-term derivative assets........ 3,793 654,647 658,440
---------- ------------- -------------
Total assets..................... $ 3,793 $ 1,127,290 $ 1,131,083
========== ============= =============
Current derivative liabilities..... $ 20,207 $ 605,918 $ 626,125
Long-term derivative liabilities... 53,709 850,115 903,824
---------- ------------- -------------
Total liabilities................ $ 73,916 $ 1,456,033 $ 1,529,949
========== ============= =============
Net derivative liabilities...... $ 70,123 $ 328,743 $ 398,866
========== ============= =============
Of the Company's net derivative liabilities, $257.7 million and $50.4
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 records the
derivative assets of PCF in its balance sheet.
On March 31, 2005, Deer Park Energy Center, Limited Partnership ("Deer
Park"), an indirect, wholly owned subsidiary of Calpine, entered into agreements
to sell power to and buy gas from Merrill Lynch Commodities, Inc. ("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 a cash payment of $195.8 million, net of $17.3 million in
transaction costs, and expects to receive additional cash payments of
approximately $70 million as additional power transactions are executed with
discounts to 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
discounted pricing under the agreements resulted in the recognition of a $213.1
million derivative liability. 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.
At any point in time, it is highly unlikely that total net derivative
liabilities and liabilities will equal accumulated Other Comprehensive Income
("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 March 31, 2005 (in thousands):
Net derivative liabilities...................................... $ (398,866)
Derivatives not designated as cash flow hedges and
recognized hedge ineffectiveness............................. 136,177
Cash flow hedges terminated prior to maturity................... (61,493)
Deferred tax asset attributable to accumulated other
comprehensive loss on cash flow hedges....................... 107,637
AOCI from unconsolidated investees.............................. 11,629
-----------
Accumulated other comprehensive loss from
derivative instruments, net of tax (1)....................... $ (204,916)
===========
- ----------
(1) Amount represents one portion of the Company's total AOCI balance. See Note
9 for further information.
Presentation of Revenue Under EITF Issue No. 03-11 "Reporting Realized
Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133 and
Not `Held for Trading Purposes' As Defined in EITF Issue No. 02-3: "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" ("EITF
Issue No. 03-11") -- The Company accounts for certain of its power sales and
purchases on a net basis under EITF Issue No. 03-11, which the Company adopted
on a prospective basis on October 1, 2003. Transactions with either of the
following characteristics are presented net in the Company's Consolidated
Condensed Financial Statements: (1) transactions executed in a back-to-back buy
and sale pair, primarily because of market protocols; and (2) physical power
purchase and sale transactions where the Company's power schedulers net the
physical flow of the power purchase against the physical flow of the power sale
(or "book out" the physical power flows) as a matter of scheduling convenience
to eliminate the need to schedule actual power delivery. These book out
transactions may occur with the same counterparty or between different
counterparties where the Company has equal but offsetting physical purchase and
delivery commitments. In accordance with EITF Issue No. 03-11, the Company
netted the purchases of $303.8 million and $370.5 million against sales in the
quarters ended March 31, 2005, and March 31, 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
March 31, 2005.
March 31, 2005
-----------------------------
Gross Net
------------- -------------
Current derivative assets................ $ 1,680,922 $ 472,643
Long-term derivative assets.............. 1,487,952 654,647
------------- -------------
Total derivative assets................ $ 3,168,874 $ 1,127,290
============= =============
Current derivative liabilities........... $ 1,814,197 $ 605,918
Long-term derivative liabilities......... 1,683,420 850,115
------------- -------------
Total derivative liabilities........... $ 3,497,617 $ 1,456,033
============= =============
Net commodity derivative liabilities.. $ 328,743 $ 328,743
============= =============
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 months ended March 31, 2005
and 2004, respectively (in thousands):
Three Months Ended March 31,
--------------------------------------------------------------------------------
2005 2004
-------------------------------------- ----------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ----------- --------- --------------- ------------ ----------
Natural gas derivatives (1)....................... $1,196 $ (14,468) $ (13,272) $5,446 $ 637 $ 6,083
Power derivatives (1)............................. (1,038) 23,148 22,110 (540) (10,488) (11,028)
Interest rate derivatives (2)..................... (33) -- (33) (398) 96 (302)
------ --------- --------- ------ --------- ---------
Total........................................... $ 125 $ 8,680 $ 8,805 $4,508 $ (9,755) $ (5,247)
====== ========= ========= ====== ========= =========
- ----------
<FN>
(1) Represents the unrealized portion of mark-to-market activity on gas and
power transactions. The unrealized portion of mark-to-market activity is
combined with the realized portions of mark-to-market activity and
presented in the Consolidated Statements of Operations as mark-to-market
activities, net.
(2) Recorded within Other Income.
</FN>
The table below reflects the contribution of the Company's cash flow hedge
activity to pre-tax earnings based on the reclassification adjustment from OCI
to earnings for the three months ended March 31, 2005 and 2004, respectively (in
thousands):
2005 2004
------------ ------------
Natural gas and crude oil derivatives... $ 28,800 $ 193
Power derivatives....................... (17,772) (12,768)
Interest rate derivatives............... (6,481) (2,772)
Foreign currency derivatives............ (503) (516)
----------- -----------
Total derivatives..................... $ 4,044 $ (15,863)
=========== ===========
As of March 31, 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 12 years, for commodity and interest rate derivative
instruments, respectively. The Company estimates that pre-tax losses of $192.0
million would be reclassified from AOCI into earnings during the twelve months
ended March 31, 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):
2010 &
2005 2006 2007 2008 2009 After Total
---------- ---------- ---------- ---------- ---------- ---------- -----------
Gas OCI......................................... $ 121,379 $ 81,225 $ 2,154 $ 1,500 $ 1,001 $ 1,077 $ 208,336
Power OCI....................................... (245,869) (213,089) (7,477) (2,730) (2,007) (1,529) (472,701)
Interest rate OCI............................... (7,112) (6,456) (4,274) (3,357) (3,138) (18,606) (42,943)
Foreign currency OCI............................ (1,508) (2,011) (1,620) (108) -- -- (5,247)
--------- --------- --------- --------- -------- --------- ----------
Total pre-tax OCI............................. $(133,110) $(140,331) $ (11,217) $ (4,695) $ (4,144) $ (19,058) $ (312,555)
========= ========= ========= ========= ======== ========= ==========
9. Comprehensive Income (Loss)
Comprehensive income is the total of net income and all other non-owner
changes in equity. Comprehensive income includes the Company's net income,
unrealized gains and losses from derivative instruments that qualify as cash
flow hedges, 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 three months ended March 31, 2005 and 2004 in the Company's
AOCI balance and the components of the Company's comprehensive income (in
thousands):
Total Comprehensive
Accumulated Income (Loss)
Available- Foreign Other for the Three
Cash Flow for-Sale Currency Comprehensive Months Ended
Hedges Investments Translation Income (Loss) March 31, 2005
------------ ----------- ----------- ------------ ---------------
Accumulated other comprehensive income (loss) at
January 1, 2005.......................................... $ (140,151) $ 582 $ 249,080 $ 109,511
Net loss................................................... $ (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
=========== ======== ========== ==========
Total Comprehensive
Accumulated Income (Loss)
Available- Foreign Other for the Three
Cash Flow for-Sale Currency Comprehensive Months Ended
Hedges Investments Translation Income (Loss) March 31, 2004
------------ ----------- ----------- ------------ ---------------
Accumulated other comprehensive income (loss) at
January 1, 2004.......................................... $ (130,419) $ -- $ 187,013 $ 56,594
Net loss................................................... $ (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
=========== ======== ========== ==========
10. 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).
Periods Ended March 31,
----------------------------------------------------------------------
2005 2004
---------------------------------- ----------------------------------
Net Loss Shares EPS Net Loss Shares EPS
------------ ------- ------- ------------ ------- --------
THREE MONTHS:
Basic and diluted loss per common share:
Loss before discontinued operations........................ $ (168,731) 447,599 $ (0.38) $ (107,232) 415,308 $ (0.26)
Discontinued operations, net of tax........................ -- -- -- 36,040 -- 0.09
----------- -------- ------- ----------- -------- -------
Net loss................................................ $ (168,731) 447,599 $ (0.38) $ (71,192) 415,308 $ (0.17)
=========== ======= ======= =========== ======= =======
The Company incurred losses before discontinued operations and cumulative
effect of a change in accounting principle for the quarters ended March 31, 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 11.4 million and 72.6 million shares of the Company's common stock
were not included in the computation of diluted shares outstanding during the
quarters ended March 31, 2005 and 2004, respectively, because such inclusion
would be antidilutive.
For the quarters ended March 31, 2005 and 2004, approximately 0.1 million
and 23.8 million, respectively, weighted common shares of the Company's
outstanding 2006 Convertible Senior Notes were excluded from the diluted EPS
calculations as the inclusion of such shares would have been antidilutive.
In connection with the convertible debentures payable to Calpine Capital
Trust III, net of repurchases, for the quarters ended March 31, 2005 and 2004,
there were 9.3 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.
For the quarters ended March 31, 2005 and 2004, under 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
Senior Notes issued in November 2003, 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 $6.50 and the Company
has income before discontinued operations and cumulative effect of a change in
accounting principle, the maximum potential shares issuable under the conversion
provisions of the 2023 Convertible Senior Notes and included (if dilutive) in
the diluted EPS calculation is approximately 97.5 million shares; the actual
number of potential shares depends on the closing stock price at conversion.
Similarly, for the quarter ended March 31, 2005, under 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 outstanding 2014
Convertible Notes as the inclusion of such shares would have been antidilutive
because of the Company's net loss. However, in future reporting periods when the
Company has income before discontinued operations and cumulative effect of a
change in accounting principle and the closing stock price is above $3.85, the
maximum potential shares issuable under the conversion provisions of the 2014
Convertible Notes and included in the diluted EPS calculation is approximately
191.2 million shares; the actual number of potential shares depends on the
closing stock price at conversion.
For the quarter ended March 31, 2005, 318,787 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.
In conjunction with the 2014 Convertible Notes offering, the Company
entered into a ten-year Share Lending Agreement with Deutsche Bank AG London
("DB London"), under which the Company loaned DB London 89 million shares of
newly issued Calpine common stock in exchange for a loan fee of $.001 per share.
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.
11. Commitments and Contingencies
Turbines. The table below sets forth future turbine payments for
construction and development projects, as well as for unassigned turbines. It
includes previously delivered turbines, payments and delivery by year for the
last turbine to be delivered as well as payment required for the potential
cancellation costs of the remaining 38 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 38 turbines.
Units to Be
Year Total Delivered
--------------------------------- -------------- -----------
(In thousands)
April through December 2005...... $ 27,513 1
2006............................. 4,862 --
2007............................. 977 --
---------- ---
Total............................ $ 33,352 1
========== ===
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. There is currently only one claim
remaining from the consolidated actions: a claim for violation of Section 11 of
the Securities Act of 1933 ("Securities Act"). The Court has dismissed all of
the claims brought under Section 10(b) of the Securities Exchange Act of 1934
with prejudice.
On October 17, 2003, plaintiffs filed their third amended complaint
("TAC"), which alleges violations of Section 11 of the Securities Act by
Calpine, Peter Cartwright, Ann B. Curtis and Charles B. Clark, Jr. The TAC
alleges that the registration statement and prospectuses for Calpine's 2011
Notes contained materially false or misleading statements about the factors that
caused the power shortages in California in 2000-2001 and the resulting increase
in wholesale energy prices. The lead plaintiff in this action contends that the
true but undisclosed cause of the energy crisis is that Calpine and other power
producers were engaging in physical and economic withholding of electricity. The
TAC defines the potential class to include all purchasers of the Notes pursuant
to the registration statement and prospectuses on or before January 27, 2003.
The Court has not yet certified the class. The class certification hearing is
set for May 10, 2005.
The Court has set a November 7, 2005 trial date. Fact discovery will close
on July 1, 2005. Lead plaintiff has moved for a 120 day extension of fact
discovery and other deadlines, which necessarily would affect the trial date. We
consider the lawsuit to be without merit and intend to continue to defend
vigorously against the allegations.
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, but defendants won a motion to transfer the case to
Santa Clara County. Defendants in this case are Calpine, Cartwright, Curtis,
John Wilson, Kenneth Derr, George Stathakis, CSFB, Banc of America Securities,
Deutsche Bank Securities, and Goldman, Sachs & Co. Plaintiff is the Hawaii
Structural Ironworkers Pension Trust Fund.
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 discovery cut off date or trial date in this action. The next
scheduled court hearing will be a case management conference on July 5, 2005, at
which time the court may set a discovery deadline and 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 Employee Retirement Income Security Act ("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 Calpine Corporation Retirement Savings Plan (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.
Defendants moved to dismiss the Consolidated Complaint. Judge Armstrong
granted the motion and dismissed three of the four claims with prejudice. The
fourth claim was dismissed with leave to amend. We expect the second amended
consolidated complaint to be filed on May 9, 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
the above-described federal Section 11 action 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 ever 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 have been filed to
dismiss the action against certain of the director defendants on the grounds of
lack of personal jurisdiction, as well as to dismiss the complaint in total on
other grounds. In February 2003, plaintiff agreed to stay these proceedings
until the above-described federal Section 11 action 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 ever lifted.
International Paper Company v. Androscoggin Energy LLC. In October 2000,
International Paper Company ("IP") 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 cost 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. AELLC filed a counterclaim against IP that has been referred to
arbitration that AELLC may commence at its discretion upon further evaluation.
On November 7, 2002, the court issued an opinion on the parties' cross motions
for summary judgment finding in AELLC's favor on certain matters though granting
summary judgment to IP on the liability aspect of a particular claim against
AELLC. The court also denied a motion submitted by IP for preliminary injunction
to permit IP to make payment of funds into escrow (not directly to AELLC) and
require AELLC to post a significant bond.
In mid-April of 2003, IP unilaterally availed itself to self-help in
withholding amounts in excess of $2 million as a setoff for litigation expenses
and fees incurred to date as well as an estimated portion of a rate fund to
AELLC. AELLC has submitted an amended complaint and request for immediate
injunctive relief against such actions. The court heard the motion on April 24,
2003 and ordered that IP must pay the approximate $1.2 million withheld as
attorneys' fees related to the litigation as any such perceived entitlement was
premature, but declined to order injunctive relief on the incomplete record
concerning the offset of $799,000 as an estimated pass-through of the rate fund.
IP complied with the order on April 29, 2003 and tendered payment to AELLC of
the approximate $1.2 million. On June 26, 2003, the court entered an order
dismissing AELLC's amended counterclaim without prejudice to AELLC re-filing the
claims as breach of contract claims in a separate lawsuit. On December 11, 2003,
the court denied in part IP's summary judgment motion pertaining to damages. In
short, the court: (i) determined that, as a matter of law, IP is entitled to
pursue an action for damages as a result of AELLC's breach, and (ii) ruled that
sufficient questions of fact remain to deny IP summary judgment on the measure
of damages as IP did not sufficiently establish causation resulting from AELLC's
breach of contract (the liability aspect of which IP obtained a summary judgment
in December 2002). On February 2, 2004, the parties filed a Final Pretrial Order
with the court. The case recently proceeded to trial, and on November 3, 2004, a
jury verdict in the amount of $41 million was rendered in favor of IP. AELLC was
held liable on the misrepresentation claim, but not on the breach of contract
claim. The verdict amount was based on calculations proffered by IP's damages
experts. 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. If the judgment is not vacated as a result of the
post-trial motions, 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. As noted above, 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. 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. No request has been made for the appointment of a trustee or examiner in
the proceeding, and no official committee of unsecured creditors has yet been
appointed by the Office of the United States Trustee.
Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On
November 5, 2003, Panda Energy International, Inc. and certain related parties,
including PLC II, LLC, (collectively "Panda") filed suit against Calpine and
certain of its affiliates in the United States District Court for the Northern
District of Texas, alleging, among other things, that the Company breached
duties of care and loyalty allegedly owed to Panda by failing to correctly
construct and operate the Oneta Energy Center ("Oneta"), which the Company
acquired from Panda, in accordance with Panda's original plans. Panda alleges
that it is entitled to a portion of the profits from Oneta and that Calpine's
actions have reduced the profits from Oneta thereby undermining Panda's ability
to repay monies owed to Calpine on December 1, 2003, under a promissory note on
which approximately $38.6 million (including interest through December 1, 2003)
is currently outstanding and past due. The note is collateralized by Panda's
carried interest in the income generated from Oneta, which achieved full
commercial operations in June 2003. Calpine filed a counterclaim against Panda
Energy International, Inc. (and PLC II, LLC) based on a guaranty and a motion to
dismiss as to the causes of action alleging federal and state securities laws
violations. The court recently granted Calpine's motion to dismiss, but allowed
Panda an opportunity to replead. The Company considers Panda's lawsuit to be
without merit and intends 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 in repayment
of the note.
California Business & Professions Code Section 17200 Cases, of which the
lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C.,
et al. This purported class action complaint filed in May 2002 against 20 energy
traders and energy companies, including Calpine Energy Services, L.P., ("CES"),
alleges that defendants exercised market power and manipulated prices in
violation of California Business & Professions Code Section 17200 et seq., and
seeks injunctive relief, restitution, and attorneys' fees. The Company also has
been named in eight other similar complaints for violations of Section 17200.
The Company considers the allegations to be without merit, and filed a motion to
dismiss on August 28, 2003. The court granted the motion, and plaintiffs
appealed. The Ninth Circuit has issued a decision affirming the dismissal of the
Pastorino group of cases.
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. The
Company considers the allegations to be without merit, and has filed a demurrer.
Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy
Services, L.P. before the FERC, filed on December 4, 2001, Nevada Section 206
Complaint. On December 4, 2001, Nevada Power Company ("NPC") and Sierra Pacific
Power Company ("SPPC") filed a complaint with FERC under Section 206 of the
Federal Power Act against a number of parties to their power sales agreements,
including Calpine. NPC and SPPC allege in their complaint, 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 March 16,
2004, NPC filed a petition for declaratory order at FERC (Docket No.
EL04-90-000) asking that an order be issued requiring Calpine and Reliant Energy
Services, Inc. ("Reliant") to pay for transmission service under their
Transmission Service Agreements ("TSAs") with NPC or, if the TSAs are
terminated, to pay the lesser of the transmission charges or a pro rata share of
the total cost of NPC's Centennial Project (approximately $33 million for
Calpine). The Centennial Project involves construction of various transmission
facilities in two phases; Calpine's Moapa Energy Center ("MEC") was scheduled to
receive service under its TSA from facilities yet to be constructed in the
second phase of the Centennial Project. Calpine filed a protest to the petition
asserting that (a) Calpine would take service under the TSA if NPC proceeds to
execute a PPA with MEC based on MEC's winning bid in the Request for Proposals
that NPC conducted in 2003; (b) if NPC did not execute a PPA with MEC, Calpine
would terminate the TSA and any payment by Calpine would be limited to a pro
rata allocation of certain costs incurred by NPC in connection with the second
phase of the project (approximately $4.5 million in total to date) among the
three customers to be served.
On November 18, 2004, FERC issued a decision in Docket No. EL04-90-000
which found that neither Calpine nor Reliant had the right to unilaterally
terminate their respective TSAs, and that upon commencement of service both
Calpine and Reliant would be obligated to pay either the associated demand
charges for service or their respective share of the capital cost associated
with the transmission upgrades that have been made in order to provide such
service. The November 18, 2004 order, however, did not indicate the amount or
measure of damages that would be owed to NPC in the event that either Calpine or
Reliant breached its respective obligations under the TSAs.
On December 10, 2004, NPC filed a request for rehearing of the November 18,
2004 decision, alleging that FERC had erred in holding that a determination of
damages for breach of either Calpine or Reliant was premature and that both
Calpine and Reliant had breached their respective TSAs. Calpine filed an answer
on January 4, 2005 requesting that FERC deny NPC's request for rehearing. On
April 20, 2005, FERC issued its Order Denying Request for Rehearing. In the
Order, the Commission denies Nevada Power's request for rehearing stating that
it finds that the dispute between Calpine and Nevada Power is "effectively a
contractual interpretation dispute" and does not warrant assertion of the
Commission's primary jurisdiction and is best left to a court.
In light of the November 18, 2004 order, on November 22, 2004 Calpine
delivered to NPC a notice (the "November 22, 2004 Letter") that it did not
intend to perform its obligations under the Calpine TSA, that NPC should
exercise its duty to mitigate its damages, if any, and that NPC should not incur
any additional costs or expenses in reliance upon the TSA for Calpine's account.
Calpine introduced the November 22, 2004 Letter into evidence in proceedings
before the Public Utilities Commission of Nevada ("PUCN") regarding NPC's third
amendment to its integrated resource plan ("Resource Plan"). In the Resource
Plan, NPC sought approval to proceed with the construction of the second phase
of the Centennial Project (the transmission project intended to serve the
Calpine and Reliant TSAs) (the "HAM Line"). On December 28, 2004, the PUCN
issued an order granting NPC's request to proceed with the construction of the
HAM Line. On January 11, 2005, Calpine filed a petition for reconsideration of
the December 28, 2004 order. On February 9, 2005, the PUCN issued an order
denying Calpine's petitions for reconsideration. At this time Calpine is unable
to predict the impact of the December 28, 2004 and the February 9, 2005 PUCN
orders, if any on the District Court Complaint (discussed below) or any possible
action by NPC before FERC regarding Calpine's notice that it will not perform
its obligations under the Calpine TSA.
Calpine had previously provided security to NPC for Calpine's share of the
HAM Line costs, in the form of a surety bond issued by Fireman's Fund Insurance
Company ("FFIC"). The bond issued by FFIC, by its terms, expired on May 1, 2004.
On or about April 27, 2004, NPC asserted to FFIC that Calpine had committed a
default under the bond by failing to agree to renew or replace the bond upon its
expiration and made demand on FFIC for the full amount of the surety bond,
$33,333,333. On April 29, 2004, FFIC filed a complaint for declaratory relief in
state superior court of Marin County, California in connection with this demand.
FFIC's complaint sought an order declaring that (a) FFIC has no obligation
to make payment under the bond; and (b) if the court were to determine that FFIC
has an obligation to make payment, then (i) Calpine has an obligation to replace
it with funds equal to the amount of NPC's demand against the bond and (ii)
Calpine is obligated to indemnify and hold FFIC harmless for all loss, costs and
fees incurred as a result of the issuance of the bond. Calpine filed an answer
denying the allegations of the complaint and asserting affirmative defenses,
including that it has fully performed its obligations under the TSA and surety
bond. NPC filed a motion to quash service for lack of personal jurisdiction in
California.
On September 3, 2004, the superior court granted NPC's motion, and NPC was
dismissed from the proceeding. Subsequently, FFIC agreed to dismiss the
complaint as to Calpine. On September 30, 2004 NPC filed a complaint in state
district court of Clark County, Nevada against Calpine, Moapa Energy Center,
LLC, FFIC and unnamed parties alleging, among other things, breach by Calpine of
its obligations under the TSA and breach by FFIC of its obligations under the
surety bond. On November 4, 2004, the case was removed to Federal District
Court. At this time, Calpine is unable to predict the outcome of this
proceeding.
Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6,
2002, Calpine Canada Natural Gas Partnership ("Calpine Canada") filed a
complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp.
("Enron Canada") owed it approximately US$1.5 million from the sale of gas in
connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron
Canada has not sought bankruptcy relief and has counterclaimed in the amount of
US$18 million. Discovery is currently in progress, and the Company believes that
Enron Canada's counterclaim is without merit and intends to vigorously defend
against it.
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 Darrell Jones of National Energy Systems Company ("NESCO"). The agreement
provided, among other things, that upon "Substantial Completion" of the
Goldendale facility, Calpine would pay Mr. Jones (i) $6.0 million and (ii) $18.0
million less $0.2 million per day for each day that elapsed between July 1,
2002, and the date of substantial completion. Substantial completion of the
Goldendale facility occurred in September 2004 and the daily reduction in the
payment amount has reduced the $18.0 million payment to zero. 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, and both parties have filed
briefs with the appellate court.
Calpine Energy Services v. Acadia Power Partners. Calpine, through its
subsidiaries, owns 50% of Acadia Power Partners, LLC ("Acadia PP") which company
owns the Acadia Energy Center near Eunice, Louisiana (the "Facility"). A Cleco
Corp subsidiary owns the remaining 50% of Acadia PP. CES is the purchaser under
two power purchase agreements ("PPAs") with Acadia PP, which agreements entitle
CES to all of the Facility's capacity and energy. In August 2003 certain
transmission constraints previously unknown to CES and Acadia PP began to
severely limit the ability of CES to obtain all of the energy from the Facility.
CES has asserted that it is entitled to certain relief under the purchase
agreements, to which assertions Acadia PP disagrees. Accordingly, the parties
are engaged in the alternative dispute resolution steps set forth in the PPAs.
Recently, the parties executed a tolling agreement to extend the time for
binding arbitration (up to and including until July 23, 2005) in order for
negotiations to continue. CES, however, can initiate arbitration if settlement
is not progressing appropriately. It is expected that the parties will be able
to resolve these disputes, and that Acadia PP could be liable to CES for an
amount up to $3.1 million.
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. The parties have agreed to discuss possible
resolution alternatives to litigation.
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 alleges 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 claims 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. Portis has 30 days to file an objection
and request a hearing before a Administrative Law Judge. Otherwise, the DOL's
findings become final. The Company considers Portis' complaint to be without
merit and intends to continue to vigorously defend against the complaint.
Auburndale Power Partners and Cutrale. Calpine Corporation owns an interest
in the Auburndale Power Partners ("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 entitled to damages due to Auburndale
PP's failure to provide them with steam 24 hours a day. Auburndale PP believes
that Cutrale's position is not supported by the language of the contract in
place between Auburndale PP and Cutrale and that it will prevail in arbitration.
Nevertheless, to preserve its positive relationship with Cutrale, Auburndale PP
will continue 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
"Application") in the Supreme Court of Nova Scotia against Calpine 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
Calpine Canada Resources Company (formerly Calpine Canada Resources Ltd.)
("CCR"), the parent company of Finance II and the indirect parent company of the
owner of the Saltend Energy Centre (the "Saltend Facility"), Saltend
Cogeneration Company Limited. The Bonds have been guaranteed by Calpine. The
Application alleges that Calpine and the named subsidiaries violated the Harbert
Fund's rights under certain Nova Scotia and Canadian laws in connection with
certain financing transactions completed by subsidiaries of CCR that are also
named in the Application and may violate the Harbert Fund's rights under such
laws in connection with the proposed sale of the Saltend Facility. The Harbert
Fund seeks relief under such laws including interim and permanent injunctive
relief freezing at, or tracing and returning to, CCR, assets including the
proceeds of the financing transactions and proceeds of any sale of the Saltend
Facility. The return date on the Application is August 31 and September 1, 2005.
Calpine believes that it and its subsidiaries named in the Application have
strong defenses under Nova Scotia law to the requests for final relief advanced
by the Harbert Fund and that the Harbert Fund, on a balance of probabilities,
will not likely prevail in its application before the Nova Scotia Supreme Court
for final relief. Calpine and the subsidiaries named in the Application 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.
12. Operating Segments
The Company is first and foremost an electric generating company. In
pursuing this business strategy, it has been the Company's objective to produce
a portion of its fuel consumption requirements from its own natural gas reserves
("equity gas"). The Company's oil and gas production and marketing activity has
reached the quantitative criteria to be considered a reportable segment under
SFAS No. 131. The Company's segments are therefore electric generation and
marketing; oil and gas production and marketing; and corporate and other
activities. Electric generation and marketing includes the development,
acquisition, ownership and operation of power production facilities, hedging,
balancing, optimization, and trading activity transacted on behalf of the
Company's power generation facilities. Oil and gas production includes the
ownership and operation of gas fields, gathering systems and gas pipelines for
internal gas consumption, third party sales and hedging, balancing,
optimization, and trading activity transacted on behalf of the Company's oil and
gas operations. Corporate activities and other consists primarily of financing
transactions, activities of the Company's parts and services businesses, and
general and administrative costs. Certain costs related to company-wide
functions are allocated to each segment, such as interest expense, distributions
on HIGH TIDES prior to October 1, 2003, and interest income, which are allocated
based on a ratio of segment assets to total assets.
The Company evaluates performance based upon several criteria including
profits before tax. The accounting policies of the operating segments are the
same as those described in Note 2. The financial results for the Company's
operating segments have been prepared on a basis consistent with the manner in
which the Company's management internally disaggregates financial information
for the purposes of assisting in making internal operating decisions.
Due to the integrated nature of the business segments, estimates and
judgments have been made in allocating certain revenue and expense items, and
reclassifications have been made to 2004 periods to present the allocation
consistently.
Oil and Gas
Electric Generation Production Corporate and
and Marketing and Marketing Other Total
----------------------- ------------------ ------------------ -----------------------
2005 2004 2005 2004 2005 2004 2005 2004
---------- ----------- -------- -------- -------- ------- ---------- -----------
(In thousands)
For the three months ended March 31,
Total revenue from external customers. $2,182,721 $1,998,192 $10,820 $14,135 $19,137 $19,965 $2,212,678 $2,032,292
Intersegment revenue.................. -- -- 43,011 53,066 -- -- 43,011 53,066
Segment profit/(loss) before
provision for income taxes.......... (317,735) (212,062) 6,900 13,052 57,295 18,546 (253,540) (180,464)
Electric Oil and Gas
Generation Production Corporate
and Marketing and Marketing and Other Total
------------- ------------- ------------ --------------
(In thousands)
Total assets:
March 31, 2005................................................. $ 25,411,769 $ 802,122 $ 1,365,576 $ 27,579,467
December 31, 2004.............................................. $ 25,187,414 $ 998,810 $ 1,029,864 $ 27,216,088
Intersegment revenues primarily relate to the use of internally procured
gas by the Company's power plants. These intersegment revenues have been
included in Segment profit (loss) before provision for income taxes in the oil
and gas production and marketing reporting segment and eliminated in the
corporate and other reporting segment.
13. California Power Market
California Refund Proceeding. On August 2, 2000, the California Refund
Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric
Company under Section 206 of the Federal Power Act alleging, among other things,
that the markets operated by the California Independent System Operator
("CAISO") and the California Power Exchange ("CalPX") were dysfunctional. FERC
established a refund effective period of October 2, 2000, to June 19, 2001 (the
"Refund Period"), for sales made into those markets.
On December 12, 2002, an 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
issued an order (the "March 26 Order") adopting many of the findings set forth
in the December 12 Certification. 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 California Refund Proceeding. The Company
believes, based on information that the Company has analyzed to date, that any
refund liability that may be attributable to it could total approximately $9.9
million (plus interest, if applicable), after taking the appropriate set-offs
for outstanding receivables owed by the CalPX and CAISO to Calpine. The Company
believes it has appropriately reserved for the refund liability that by its
current analysis would potentially be owed under the refund calculation
clarification in the March 26 Order. The final determination of the refund
liability and the allocation of payment obligations among the numerous buyers
and sellers in the California markets is subject to further Commission
proceedings. 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. Thus, the impact on the Company's business is
uncertain.
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 CPUC, the CDWR, and the EOB. Also, on
April 27, 2004, The Williams Companies, Inc. ("Williams") entered into a
settlement of the California Refund Proceeding and other proceedings with the
three California investor-owned utilities; previously, Williams had entered into
a settlement of the same matters with the California governmental entities. The
Williams settlement with the California governmental entities was similar to the
settlement that Calpine entered into with the California governmental entities
on April 22, 2002. Calpine's settlement resulted in a FERC order issued on March
26, 2004, which partially dismissed Calpine from the California Refund
Proceeding to the extent that any refunds are owed for power sold by Calpine to
CDWR or any other agency of the State of California. On June 30, 2004, a
settlement conference was convened at the FERC to explore settlements among
additional parties. 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.
FERC Investigation into Western Markets. On February 13, 2002, FERC
initiated an investigation of potential manipulation of electric and natural gas
prices in the western United States. This investigation was initiated as a
result of allegations that Enron and others used their market position to
distort electric and natural gas markets in the West. The scope of the
investigation is to consider whether, as a result of any manipulation in the
short-term markets for electric energy or natural gas or other undue influence
on the wholesale markets by any party since January 1, 2000, the rates of the
long-term contracts subsequently entered into in the West are potentially unjust
and unreasonable. On August 13, 2002, the FERC staff issued the Initial Report
on Company-Specific Separate Proceedings and Generic Reevaluations; Published
Natural Gas Price Data; and Enron Trading Strategies (the "Initial Report"),
summarizing its initial findings in this investigation. There were no findings
or allegations of wrongdoing by Calpine set forth or described in the Initial
Report. On March 26, 2003, the FERC staff issued a final report in this
investigation (the "Final Report"). In the Final Report, the FERC staff
recommended that FERC issue a show cause order to a number of companies,
including Calpine, regarding certain power scheduling practices that may have
been in violation of the CAISO's or CalPX's tariff. The Final Report also
recommended that FERC modify the basis for determining potential liability in
the California Refund Proceeding discussed above. Calpine believes that it did
not violate these tariffs and that, to the extent that such a finding could be
made, any potential liability would not be material.
Also, on June 25, 2003, FERC issued a number of orders associated with
these investigations, including the issuance of two show cause orders to certain
industry participants. FERC did not subject Calpine to either of the show cause
orders. FERC also issued an order directing the FERC Office of Markets and
Investigations to investigate further whether market participants who bid a
price in excess of $250 per megawatt hour into markets operated by either the
CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may
have violated CAISO and CalPX tariff prohibitions. No individual market
participant was identified. The Company believes that it did not violate the
CAISO and CalPX tariff prohibitions referred to by FERC in this order; however,
the Company is unable to predict at this time the final outcome of this
proceeding or its impact on Calpine.
CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our
Qualifying Facilities ("QF") contracts with PG&E provide that the CPUC has the
authority to determine the appropriate utility "avoided cost" to be used to set
energy payments 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 CalPX market clearing price
instead of the SRAC price administratively determined by the CPUC. Having
elected such option, the Company's QF facilities were paid based upon the CalPX
zonal day-ahead clearing price ("CalPX Price") for various periods commencing in
the summer of 2000 until January 19, 2001, when the CalPX ceased operating a
day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine
whether the CalPX Price was the appropriate price for the energy component upon
which to base payments to QFs which had elected the CalPX-based pricing option.
One CPUC Commissioner at one point issued a proposed decision to the effect that
the CalPX Price was the appropriate energy price to pay QFs who selected the
pricing option then offered by Section 390. No final decision, however, has been
issued to date. Therefore, it is possible that the CPUC could order a payment
adjustment based on a different energy price determination. On January 10, 2001,
PG&E filed an emergency motion (the "Emergency Motion") requesting that the CPUC
issue an order that would retroactively change the energy payments received by
QFs based on CalPX-based pricing for electric energy delivered during the period
commencing during June 2000 and ending on January 18, 2001. On April 29, 2004,
PG&E, the Utility Reform Network, a consumer advocacy group, and the Office of
Ratepayer Advocates, 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 2004 Motion"). The
April 2004 Motion requests that the CPUC set a briefing schedule in R.99-11-022
to determine what is the appropriate price that should be paid to the QFs that
had switched to the CalPX Price. The PG&E Parties allege that the appropriate
price should be determined using the methodology that has been developed thus
far in the California Refund Proceeding discussed above. Supplemental pleadings
have been filed on the April 2004 Motion, but neither the CPUC nor the assigned
administrative law judge has issued any rulings with respect to either the April
2004 Motion or the initial Emergency Motion. The Company believes that the CalPX
Price was the appropriate price for energy payments for its QFs during this
period, but there can be no assurance that this will be the outcome of the CPUC
proceedings.
Geysers Reliability Must Run Section 206 Proceeding. CAISO, EOB, CPUC,
PG&E, San Diego Gas & Electric Company, and Southern California Edison Company
(collectively referred to as the "Buyers Coalition") filed a complaint on
November 2, 2001 at FERC requesting the commencement of a Federal Power Act
Section 206 proceeding to challenge one component of a number of separate
settlements previously reached on the terms and conditions of "reliability must
run" contracts ("RMR Contracts") with certain generation owners, including
Geysers Power Company, LLC, which settlements were also previously approved by
FERC. RMR Contracts require the owner of the specific generation unit to provide
energy and ancillary services when called upon to do so by the ISO to meet local
transmission reliability needs or to manage transmission constraints. The Buyers
Coalition has asked FERC to find that the availability payments under these RMR
Contracts are not just and reasonable. Geysers Power Company, LLC filed an
answer to the complaint in November 2001. To date, FERC has not established a
Section 206 proceeding. The outcome of this litigation and the impact on the
Company's business cannot be determined at the present time.
14. Subsequent Events
On April 12, 2005, the Company's unconsolidated investment AELLC sold three
fixed price gas contracts for gross cash proceeds of $116.0 million to Merrill
Lynch Commodities Canada, ULC. On April 13, 2005, a portion of the proceeds from
the sale were used to pay down the remaining construction debt outstanding of
$58.1 million as well as costs associated with the termination of an interest
rate swap agreement.
On May 9, 2005, Standard & Poor's lowered its corporate credit rating on
Calpine Corporation to single B- from single 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. The ratings
for the following debt issues remained unchanged: the BBB- SPUR rating on Gilroy
Energy Center bonds, the BB- rating on the Rocky Mountain Energy Center and the
Riverside Energy Center loans, the CCC+ rating on the third lien CalGen debt and
the BBB rating on the Power Contract Financing LLC bonds. Such downgrade could
increase the cost of future borrowings and other costs of doing business.
During the second quarter of 2005 (through May 9, 2005), the Company has
repurchased in open market transactions $116.3 million of the principal amount
of its outstanding debt as listed below:
10 1/2% Senior Notes Due 2006 $3,485,000
7 5/8% Senior Notes Due 2006 $1,335,000
8 3/4% Senior Notes Due 2007 $3,000,000
7 3/4% Senior Notes Due 2009 $35,000,000
8 5/8% Senior Notes Due 2010 $37,468,000
8 1/2% Senior Notes Due 2011 $36,000,000
The securities, which were trading at a discount to par value, were
repurchased in exchange for approximately $69.6 million in cash.
On May 10, 2005, Metcalf, the Company's indirect subsidiary, commenced a
$155 million offering of 5.5-Year Redeemable Preferred Shares. Concurrent with
the issuance of the Preferred Shares, Metcalf intends to refinance, through a
five-year, $100 Million Senior Term Loan, an existing $100 million non-recourse
construction credit facility. The proceeds from the offering of the Redeemable
Preferred Shares will be used as permitted by Calpine's existing bond
indentures. Proceeds from the offering of the Senior Term Loan will be used to
refinance all outstanding indebtedness under the existing construction credit
facility, to complete construction of the Metcalf power plant, to pay fees and
expenses related to the transaction, and as permitted by Calpine's existing bond
indentures.
Item 2. Management's Discussion and Analysis ("MD&A") of Financial Condition and
Results of Operations.
In addition to historical information, this report contains forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended. We
use words such as "believe," "intend," "expect," "anticipate," "plan," "may,"
"will" and similar expressions to identify forward-looking statements. Such
statements include, among others, those concerning our expected financial
performance and strategic and operational plans, as well as all assumptions,
expectations, predictions, intentions or beliefs about future events. You are
cautioned that any such forward-looking statements are not guarantees of future
performance and that a number of risks and uncertainties could cause actual
results to differ materially from those anticipated in the forward-looking
statements. Such risks and uncertainties include, but are not limited to, (i)
the timing and extent of deregulation of energy markets and the rules and
regulations adopted on a transitional basis with respect thereto, (ii) the
timing and extent of changes in commodity prices for energy, particularly
natural gas and electricity, and the impact of related derivatives transactions,
(iii) unscheduled outages of operating plants, (iv) unseasonable weather
patterns that reduce demand for power, (v) economic slowdowns that can adversely
affect consumption of power by businesses and consumers, (vi) various
development and construction risks that may delay or prevent commercial
operations of new plants, such as failure to obtain the necessary permits to
operate, failure of third-party contractors to perform their contractual
obligations or failure to obtain project financing on acceptable terms, (vii)
uncertainties associated with cost estimates, that actual costs may be higher
than estimated, (viii) development of lower-cost power plants or of a lower cost
means of operating a fleet of power plants by our competitors, (ix) risks
associated with marketing and selling power from power plants in the evolving
energy market, (x) factors that impact exploitation of oil or gas resources,
such as the geology of a resource, the total amount and costs to develop
recoverable reserves, and legal title, regulatory, gas administration, marketing
and operational factors relating to the extraction of natural gas, (xi)
uncertainties associated with estimates of oil and gas reserves, (xii) the
effects on our business resulting from reduced liquidity in the trading and
power generation industry, (xiii) our ability to access the capital markets on
attractive terms or at all, (xiv) uncertainties associated with estimates of
sources and uses of cash, that actual sources may be lower and actual uses may
be higher than estimated, (xv) the direct or indirect effects on our business of
a lowering of our credit rating (or actions we may take in response to changing
credit rating criteria), including increased collateral requirements, refusal by
our current or potential counterparties to enter into transactions with us and
our inability to obtain credit or capital in desired amounts or on favorable
terms, (xvi) present and possible future claims, litigation and enforcement
actions, (xvii) effects of the application of regulations, including changes in
regulations or the interpretation thereof, and (xviii) other risks identified in
this report. You should also carefully review the risks described in other
reports that we file with the Securities and Exchange Commission, including
without limitation our annual report on Form 10-K for the year ended December
31, 2004. We undertake no obligation to update any forward-looking statements,
whether as a result of new information, future developments or otherwise.
We file annual, quarterly and periodic reports, proxy statements and other
information with the SEC. You may obtain and copy any document we file with the
SEC at the SEC's public reference room at 450 Fifth Street, N.W., Washington,
D.C. 20549. You may obtain information on the operation of the SEC's public
reference facilities by calling the SEC at 1-800-SEC-0330. You can request
copies of these documents, upon payment of a duplicating fee, by writing to the
SEC at its principal office at 450 Fifth Street, N.W., Washington, D.C.
20549-1004. The SEC maintains an Internet website at http://www.sec.gov that
contains reports, proxy and information statements, and other information
regarding issuers that file electronically with the SEC. Our SEC filings are
accessible through the Internet at that website.
Our reports on Forms 10-K, 10-Q and 8-K, and amendments to those reports,
are available for download, free of charge, as soon as reasonably practicable
after these reports are filed with the SEC, at our website at www.calpine.com.
The content of our website is not a part of this report. You may request a copy
of our SEC filings, at no cost to you, by writing or telephoning us at: Calpine
Corporation, 50 West San Fernando Street, San Jose, California 95113, attention:
Lisa M. Bodensteiner, Assistant Secretary, telephone: (408) 995-5115.
We will not send exhibits to the documents, unless the exhibits are specifically
requested and you pay our fee for duplication and delivery.
Selected Operating Information
Set forth below is certain selected operating information for our power
plants for which results are consolidated in our Consolidated Condensed
Statements of Operations. Electricity revenue is composed of fixed capacity
payments, which are not related to production, and variable energy payments,
which are related to production. Capacity revenues include, besides traditional
capacity payments, other revenues such as Reliability Must Run and Ancillary
Service revenues. The information set forth under thermal and other revenue
consists of host steam sales and other thermal revenue.
Three Months Ended March 31,
--------------------------------
2005 2004
-------------- --------------
(In thousands, except
pricing data)
Power Plants:
Electricity and steam ("E&S") revenues:
Energy............................................... $ 1,035,501 $ 932,497
Capacity............................................. 254,191 181,464
Thermal and other.................................... 113,857 131,926
------------- --------------
Subtotal............................................. $ 1,403,549 $ 1,245,887
Spread on sales of purchased power (1)................. 67,343 5,089
------------- --------------
Adjusted E&S revenues (non-GAAP)....................... $ 1,470,892 $ 1,250,976
Megawatt hours produced................................ 22,360 21,050
All-in electricity price per megawatt hour generated... $ 65.78 $ 59.43
- ----------
<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 months ended March 31, 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 March 31,
----------------------------
2005 2004
---------- ----------
Total revenue............................................... $2,212,678 $2,032,292
Sales of purchased power for hedging and optimization (1)... 356,130 380,028
As a percentage of total revenue............................ 16.1% 18.7%
Sale of purchased gas for hedging and optimization.......... 420,296 352,737
As a percentage of total revenue............................ 19.0% 17.4%
Total cost of revenue ("COR")............................... 2,072,036 1,920,139
Purchased power expense for hedging and optimization (1).... 288,787 374,939
As a percentage of total COR................................ 13.9% 19.5%
Purchased gas expense for hedging and optimization.......... 413,259 360,487
As a percentage of total COR................................ 19.9% 18.8%
- ----------
<FN>
(1) On October 1, 2003, we adopted on a prospective basis Emerging Issues Task
Force ("EITF") Issue No. 03-11 "Reporting Realized Gains and Losses on
Derivative Instruments That Are Subject to FASB Statement No. 133 and Not
`Held for Trading Purposes' As Defined in EITF Issue No. 02-3: "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes
and Contracts Involved in Energy Trading and Risk Management Activities"
("EITF Issue No. 03-11") and netted 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 Calpine Energy Services, L.P. ("CES") risk
management organization; (b) particularly volatile markets for electricity and
natural gas, which prompted us to frequently adjust our hedge positions by
buying power and gas and reselling it; and (c) the accounting requirements under
Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial
Statements," and EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal
versus Net as an 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. We provide power to our U.S., Canadian and U.K.
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 own and produce natural gas and to a lesser extent oil, which we use
primarily to lower our costs of power production and provide a natural hedge of
fuel costs for a portion of our electric power plants, but also to generate some
revenue through sales to third parties. We protect and enhance the value of our
electric and gas assets with a sophisticated risk management organization. We
also protect our power generation assets and control certain of our costs by
producing certain of the combustion turbine replacement parts that we use at our
power plants, and we generate revenue by providing combustion turbine parts to
third parties. Finally, we offer services to third parties to capture value in
the skills we have honed in building, commissioning, repairing and operating
power plants.
Our key opportunities and challenges include:
o preserving and enhancing our liquidity while spark spreads (the
differential between power revenues and fuel costs) are depressed,
o selectively adding new load-serving entities and power users to our
customer list as we increase our power contract portfolio,
o continuing to add value through prudent risk management and optimization
activities, and
o lowering our costs of production through various efficiency programs.
Since the latter half of 2001, there has been a significant contraction in
the availability of capital for participants in the energy sector. This has been
due to a range of factors, including uncertainty arising from the collapse of
Enron and a near-term surplus supply of electric generating capacity in certain
market areas. These factors coupled with a three-year period of decreased spark
spreads have adversely impacted our liquidity and earnings. We recognize that
the terms of financing available to us in the future may not be attractive. To
protect against this possibility and due to current market conditions, we scaled
back our capital expenditure program to enable us to conserve our available
capital resources. See "Capital Availability" in Liquidity and Capital Resources
below for a further discussion.
Set forth below are the Results of Operations for the three months ended
March 31, 2005 and 2004 (in millions, 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.
Set forth below are the Results of Operations for the three months ended
March 31, 2005 and 2004.
Results of Operations
Three Months Ended March 31, 2005, Compared to Three Months Ended March 31, 2004
Revenue
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Total revenue................................................ $ 2,212.7 $ 2,032.3 $ 180.4 8.9%
The change in total revenue is explained by category below.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Electricity and steam revenue................................ $ 1,403.6 $ 1,245.9 $ 157.7 12.7%
Transmission sales revenue................................... 3.7 5.7 (2.0) (35.1)%
Sales of purchased power for hedging and optimization........ 356.1 380.0 (23.9) (6.3)%
----------- ----------- -----------
Total electric generation and marketing revenue............ $ 1,763.4 $ 1,631.6 $ 131.8 8.1%
=========== =========== ===========
Electricity and steam revenue increased as average megawatts in operations
of our consolidated plants increased by 20.7% to 26,368 MW while generation
increased by 6.2%. In addition, average realized electric price before the
effects of hedging, balancing and optimization, increased from $59.19 / MWh in
2004 to $62.78 / MWh in 2005.
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. Because we increased utilization of our generating assets
during the three months ending March 31, 2005, as compared to the quarter ended
March 31, 2004, our revenues from the resale of transmission capacity declined.
Sales of purchased power for hedging and optimization decreased in the
three months ended March 31, 2005, due primarily to lower volumes which were
partially offset by higher prices, as compared to the same period in 2004.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Oil and gas sales............................................ $ 10.8 $ 14.1 $ (3.3) (23.4)%
Sales of purchased gas for hedging and optimization.......... 420.3 352.7 67.6 19.2%
----------- ----------- -----------
Total oil and gas production and marketing revenue......... $ 431.1 $ 366.8 $ 64.3 17.5%
=========== =========== ===========
Oil and gas sales are net of internal consumption, which is eliminated in
consolidation. Internal consumption decreased from $53.1 in 2004 to $43.0 in
2005 primarily as a result of lower production. Before intercompany
eliminations, oil and gas sales decreased from $67.2 in 2004 to $53.8 in 2005,
primarily as a result of a 25% decrease in production, which was partially
offset by a 10% average increase in gas prices.
Sales of purchased gas for hedging and optimization increased during 2005
due primarily to higher prices of natural gas compared to the same period in
2004.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Realized gain (loss) on power and gas
mark-to-market transactions, net........................... $ (12.3) $ 17.4 $ (29.7) (170.7)%
Unrealized gain (loss) on power and gas mark-to-market
transactions, net.......................................... 8.8 (4.9) 13.7 279.6%
----------- ----------- -----------
Mark-to-market activities, net............................. $ (3.5) $ 12.5 $ (16.0) (128.0)%
=========== =========== ===========
Mark-to-market activities, which are shown on a net basis, result from
general market price movements against our open commodity derivative positions,
including positions accounted for as trading under EITF Issue No. 02-3, "Issues
Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" ("EITF Issue No. 02-3") and other mark-to-market
activities. These commodity positions represent a small portion of our overall
commodity contract position. Realized revenue represents the portion of
contracts actually settled and is offset by a corresponding change in unrealized
gains or losses as unrealized derivative values are converted from unrealized
forward positions to cash at settlement. Unrealized gains and losses include the
change in fair value of open contracts as well as the ineffective portion of our
cash flow hedges.
The decrease in mark-to-market activities revenue in the three months ended
March 31, 2005, as compared to the same period in 2004 is due primarily to
increases in liquidity reserves on our mark-to-market positions and
mark-to-market losses on our Calpine Generating Company, LLC's ("CalGen")
option.
Cost of Revenue
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Cost of revenue.............................................. $ 2,072.0 $ 1,920.1 $ (151.9) (7.9)%
The increase in total cost of revenue is explained by category below.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Plant operating expense...................................... $ 195.6 $ 172.8 $ (22.8) (13.2)%
Transmission purchase expense................................ 23.5 19.5 (4.0) (20.5)%
Royalty expense.............................................. 10.3 5.9 (4.4) (74.6)%
Purchased power expense for hedging and optimization......... 288.8 374.9 86.1 23.0%
----------- ----------- -----------
Total electric generation and marketing expense............ $ 518.2 $ 573.1 $ 54.9 9.6%
=========== =========== ===========
Plant operating expense and transmission purchase expense both increased
due to additional power plants achieving commercial operation subsequent to
March 31, 2004.
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 decrease during the
three months ended March 31, 2005, as compared to the same period in 2004 due
primarily to a reduction in volumes as compared to the same period in 2004.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Oil and gas production expense............................... $ 11.9 $ 12.3 $ 0.4 3.3%
Oil and gas exploration expense.............................. 1.1 0.9 (0.2) (22.2)%
----------- ----------- -----------
Oil and gas operating expense................................ 13.0 13.2 0.2 1.5%
Purchased gas expense for hedging and optimization........... 413.3 360.5 (52.8) (14.6)%
----------- ----------- -----------
Total oil and gas operating and marketing expense.......... $ 426.3 $ 373.7 $ (52.6) (14.1)%
=========== =========== ===========
Purchased gas expense for hedging and optimization increased during the
three months ended March 31, 2005, due to higher natural gas prices as compared
to the same period in 2004.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Fuel Expense
Cost of oil and gas burned by power plants................... $ 915.0 $ 789.2 $ (125.8) (15.9)%
Recognized loss on gas hedges................................ 6.3 0.5 (5.9) (118.0)%
----------- ----------- -----------
Total fuel expense......................................... $ 921.3 $ 789.7 $ (131.7) (16.7)%
=========== =========== ===========
Cost of oil and gas burned by power plants increased during the three
months ended March 31, 2005, as compared to the same period in 2004 due to an
increase in gas consumption as we increased our megawatt production and higher
prices for gas excluding the effects of hedging, balancing and optimization.
Recognized (gain) loss on gas hedges decreased during the three months
ended March 31, 2005, as compared to the same period in 2004 due to unfavorable
gas price movements against our gas financial instrument hedging positions.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Depreciation, depletion and amortization expense............. $ 143.2 $ 129.4 $ (13.8) (10.7)%
Depreciation, depletion and amortization expense increased primarily due to
the additional power facilities in consolidated operations subsequent to March
31, 2004.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Operating lease expense...................................... $ 24.8 $ 27.8 $ 3.0 10.8%
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.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Other cost of revenue........................................ $ 38.2 $ 26.4 $ (11.8) (44.7)%
Other cost of revenue increased during the three months ended March 31,
2005, as compared to the same period in 2004 due primarily to $17.3 of expense
for transaction costs incurred on the closing of an agreement to sell power to
and buy gas from Merrill Lynch Commodities, Inc. ("MLCI"). See Note 8 of the
Notes to the Consolidated Financial Statements for further information.
(Income)/Expenses
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
(Income) from unconsolidated investments..................... $ (6.1) $ (1.2) $ 4.9 408.3%
The increase in income was primarily due to unplanned outages in 2004 at
our Grays Ferry power project combined with the fact that (a) in March 2004 we
purchased the remaining 50% interest in the Aries Power Plant (at which time
this plant was consolidated) and (b) effective December 2004, we ceased to
recognize our share of the operating results of Androscoggin Energy Center LLC
("AELLC") as we determined that our investment was impaired following a jury
verdict against AELLC in a breach of contract dispute with International Paper
Company ("IP"). See Notes 5 and 11 of the Notes to the Consolidated Financial
Statements for further information.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Equipment cancellation and asset impairment charge........... $ (0.1) $ 2.4 $ 2.5 104.2%
Equipment cancellation and impairment costs decreased during the three
months ended March 31, 2005, as compared to the same period in 2004 as a result
of a $2.3 termination fee recorded in 2004 in connection with the termination of
a purchase contract for heat recovery steam generator components.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Project development expense.................................. $ 8.7 $ 7.7 $ (1.0) (13.0)%
Project development expense increased during the three months ended March
31, 2005, primarily due to costs associated with preservation activities on
suspended construction projects.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Research and development expense............................. $ 7.0 $ 3.8 $ (3.2) (84.2)%
Research and development expense increased during the three months ended
March 31, 2005, as compared to the same period in 2004 primarily due to
increased personnel expenses related to new research and development programs at
our Power Systems Mfg., LLC ("PSM") subsidiary.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Sales, general and administrative expense.................... $ 57.1 $ 54.3 $ (2.8) (5.2)%
Sales, general and administrative expense increased during the three months
ended March 31, 2005, primarily due to an increase in Sarbanes-Oxley (SOX) and
tax consulting and legal fees.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Interest expense............................................. $ 348.9 $ 248.5 $ (100.4) (40.4)%
Interest expense increased as a result of higher average debt balances,
higher average interest rates and lower capitalization of interest expense.
Interest capitalized decreased from $108.5 for the three months ended March 31,
2004, to $70.4 for the three months ended March 31, 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. Additionally, during the three months ended March 31, 2005, (i)
interest expense related to our senior notes and term loans increased by $9.6;
(ii) interest expense related to our CalGen subsidiary increased $13.3; (iii)
interest expense related to our construction/project financing increased by
$16.7; (iv) interest expense related to our Calpine Construction Finance Company
L.P ("CCFC I") subsidiary increased by $2.2; and (v) interest expense related to
preferred interests increased by $13.6 primarily due to the October 2004 closing
of the $360 million offering associated with the Saltend Energy Centre
("Saltend"), and the $260 offering on January 31, 2005 by our indirect
subsidiary, Calpine European Funding (Jersey) Limited ("Calpine Jersey II").
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Interest (income)............................................ $ (14.3) $ (12.1) $ 2.2 18.2%
Interest (income) increased during the three months ended March 31, 2005,
due primarily to higher interest rates compared to the same period in 2004.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Minority interest expense.................................... $ 10.6 $ 8.4 $ (2.2) (26.2)%
Minority interest expense increased during the three months ended March 31,
2005, as compared to the same period in 2004 primarily due to an increase of
$2.0 of minority interest expense associated with the Calpine Power Income Fund
("CPIF's") 70% interest in Calpine Power Limited Partnership (CPLP").
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
(Income) from repurchases of various issuances of debt....... $ (21.8) $ (0.8) $ 21.0 2,625.0%
Income from repurchases of various issuances of debt incurred during 2005
as compared to the prior period primarily due to repurchases of various senior
notes.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Other expense (income)....................................... $ 4.0 $ (18.4) $ (22.4) (121.7)%
Other expense was $4.0 for the three months ended March 31, 2005, compared
to other income of $18.4 for the three months ended March 31, 2004. The variance
includes a $4.8 decrease in the foreign currency transaction gain between
periods. In addition, in 2004 we recorded a gain on the sale of a variety of oil
and gas properties to the Calpine Natural Gas Trust ("CNGT") of $6.2 and a
favorable warranty settlement in the amount of $5.1.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Benefit for income taxes..................................... $ (84.8) $ (73.2) $ 11.6 15.8%
During the three months ended March 31, 2005, our tax benefit increased by
$11.6 as compared to the three months ended March 31, 2004 as our pre-tax loss
increased in 2005. The effective tax rate decreased to 33.4% in 2005 compared to
40.6% in the same period in 2004 primarily due to additional valuation
allowances against deferred tax assets in 2005, thus lowering the tax benefit.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Discontinued operations, net of tax.......................... $ -- $ 36.0 $ 36.0 100%
During 2004, our discontinued operations activities were comprised
primarily of a gain, net of tax of $22.9, from the sale of our 50% interest in
the Lost Pines 1 Power Project and operating activities associated with the sale
of our Canadian natural gas reserves and petroleum assets, and the sale of our
oil and gas reserves in the Colorado Piceance Basin and New Mexico San Juan
Basin.
Three Months Ended
March 31,
------------------------
2005 2004 $ Change % Change
----------- ----------- ----------- ------------
Net loss..................................................... $ (168.7) $ (71.2) $ (97.5) (136.9)%
For the three months ended March 31, 2005, we reported revenue of $2.2
billion, representing an increase of 9% over the same period in the prior year,
and a net loss per share of $0.38, or a net loss of $168.7 million, compared to
a net loss per share of $0.17, or a net loss of $71.2 million for the same
quarter in the prior year.
For the three months ended March 31, 2005, average capacity in operation
increased by 21% to 26,368 megawatts. We generated approximately 22.4 million
megawatt-hours, which equated to a baseload capacity factor of 44%, and realized
an average spark spread of $24.10 per megawatt-hour. For the same period in
2004, we generated 21.1 million megawatt-hours, which equated to a capacity
factor of 50%, and realized an average spark spread of $20.65 per megawatt-hour.
Gross profit increased by $28.5 million, or 25%, to $140.6 million in the
three months ended March 31, 2005, over the same period in the prior year.
Despite improvements in market fundamentals, total spark spread, which increased
by $104.2 million, or 24%, in the first quarter of 2005 compared to the same
period in 2004, did not increase commensurately with the increases in plant
operating expense, transmission purchase expense, depreciation and interest
expense associated with new power plants coming on-line. In the first quarter of
2005 gross profit was reduced by transaction fees of $17.3 million associated
with prepaid commodity transactions at Deer Park Energy Center, Limited
Partnership ("Deer Park"), our indirect, wholly owned subsidiary.
During the three months ended March 31, 2005, financial results were
affected by a $100.5 million increase in interest expense, as compared to the
same period in 2004. This occurred as a result of higher debt balances, higher
average interest rates and lower capitalization of interest expense as new
plants entered commercial operation and capitalization of interest was suspended
on three partially constructed power plants. However, we recorded a $21.8
million gain from the repurchase of debt.
Other expense was $4.0 million for the three months ended March 31, 2005,
compared to other income of $18.4 million for the three months ended March 31,
2004. The difference included a $4.7 million decrease in the foreign currency
transaction gain between periods. In addition, in 2004 we recorded a gain on the
sale of a variety of oil and gas properties to the CNGT of $6.2 million and a
favorable warranty settlement in the amount of $5.1 million.
Income from discontinued operations, net of tax for the three months ended
March 31, 2004 was as a result of the gain from the sale of the Lost Pines 1
Power Project and represents the operations of the Company's Canadian and
certain U.S. oil and gas assets that were sold during the third quarter of 2004.
There were no assets held for sale as of March 31, 2005.
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 on attractive terms. The availability of such capital in
today's environment is uncertain. To date, we have obtained cash from our
operations; borrowings under credit facilities; issuances of debt, equity, trust
preferred securities and convertible debentures and contingent convertible
notes; proceeds from sale/leaseback transactions; sale or partial sale of
certain assets; prepayments received for power sales; contract monetizations;
and project financings. We have utilized this cash to fund our operations,
service or prepay debt obligations, fund acquisitions, develop and construct
power generation facilities, finance capital expenditures, support our hedging,
balancing, optimization and trading activities, and meet our other cash and
liquidity needs. We also reinvest our cash from operations into our business
development and construction program or use it to reduce debt, rather than to
pay cash dividends.
Capital Availability -- Access to capital for many in the energy sector,
including us, has been restricted since late 2001. While we have been able to
access the capital and bank credit markets in this new environment, it has been
on significantly different terms than in the past. In particular, our senior
working capital facility and term loan financings and the majority of our debt
securities offered and sold in this period have been secured by certain of our
assets and equity interests. We have also provided security to support our
prepaid commodity financing transactions. The terms of financing available to us
now and in the future may not be attractive to us and the timing of the
availability of capital is uncertain and is dependent, in part, on market
conditions that are difficult to predict and are outside of our control.
In addition, satisfying all obligations under our outstanding indebtedness,
and funding anticipated capital expenditures and working capital requirements
for the next twelve months presents us with several challenges over the near
term as our cash requirements (including our refinancing obligations) are
expected to exceed our unrestricted cash on hand and cash from operations.
Accordingly, we have in place a liquidity-enhancing program which includes
possible sales or monetizations of certain of our assets, and whether we will
have sufficient liquidity will depend on the success of that program. No
assurance can be given that our liquidity-enhancing program will be successful.
Even if our liquidity-enhancing program is successful, there can be no assurance
that we will continue our construction program without suspending further
construction or development work on one or more projects and possibly incurring
substantial impairment losses as a result. For further discussion of this see
the risk factors in our 2004 Form 10-K. See below for progress achieved in our
liquidity program during the three months ended March 31, 2005. On March 31,
2005, our cash and cash equivalents on hand totaled $0.8 billion (see Note 2 of
the Notes to Consolidated Condensed Financial Statements), and the current
portion of restricted cash totaled approximately $0.5 billion.
Liquidity Transactions in the Three Months Ended March 31, 2005:
On January 28, 2005, our indirect subsidiary Metcalf Energy Center, LLC
("Metcalf") obtained a $100.0 million, non-recourse credit facility for the
Metcalf Energy Center in San Jose, CA. Loans extended to Metcalf under the
facility will fund remaining construction activities for the 602-megawatt,
natural gas-fired power plant. The project finance facility will mature in July
2008.
On January 31, 2005, our subsidiary, Calpine Jersey, II, completed a $260.0
million offering of Redeemable Preferred Shares due July 30, 2005. The
Redeemable Preferred Shares, priced at U.S. LIBOR plus 850 basis points, were
offered at 99% of par. The proceeds from the offering of the shares were used in
accordance with the provisions of our existing bond indentures.
On March 1, 2005, our indirect subsidiary, Calpine Steamboat Holdings, LLC,
closed on a $503.0 million non-recourse project finance facility that will
provide $466.5 million to complete the construction of the Mankato Energy Center
("Mankato") in Blue Earth County, Minnesota, and the Freeport Energy Center
("Freeport") in Freeport, Texas. The remaining $36.5 million of the facility
provides a letter of credit for Mankato that is required to serve as collateral
available to Northern States Power Company if Mankato does not meet its
obligations under the power purchase agreement ("PPA"). The project finance
facility will initially be structured as a construction loan, converting to a
term loan upon commercial operations of the plant, and will mature in December
2011. The facility will initially be priced at LIBOR plus 1.75%.
On March 31, 2005, Deer Park, our indirect, wholly owned subsidiary,
entered into an agreement to sell power to and buy gas from MLCI. To assure
performance under the agreements, Deer Park granted MLCI a collateral interest
in the Deer Park Energy Center. The agreements cover 650 MW of Deer Park's
capacity and deliveries under the agreement will begin on April 1, 2005 and
continue through December 31, 2010. Under the terms of the agreements, Deer Park
will sell power to MLCI at a discount to prevailing market prices at the time
the agreements were executed. In exchange for the discounted pricing, Deer Park
received a cash payment of approximately $195.8 million, net of $17.3 million in
transaction costs, and expects to receive additional cash payments of
approximately $70 million as additional power transactions are executed at
discounts to prevailing market prices.
Debt Repurchases and Redemptions:
During the three months ended March 31, 2005, we repurchased, at a discount
in open market transactions, $31.8 million in principal amount of our
outstanding 8 1/2% Senior Notes Due 2011 in exchange for $23.0 million in cash
plus accrued interest. We also repurchased $48.7 million in principal amount of
our outstanding 8 5/8% Senior Notes Due 2010 in exchange for $35.0 million in
cash plus accrued interest. After the write-off of deferred financing costs and
unamortized discounts on the notes, we recorded a pre-tax gain on the repurchase
of debt totaling approximately $21.8 million.
During the second quarter of 2005 (through May 9, 2005), Calpine has
repurchased in open market transactions $116.3 million of the principal amount
of its outstanding debt as listed below:
10 1/2% Senior Notes Due 2006 $3,485,000
7 5/8% Senior Notes Due 2006 $1,335,000
8 3/4% Senior Notes Due 2007 $3,000,000
7 3/4% Senior Notes Due 2009 $35,000,000
8 5/8% Senior Notes Due 2010 $37,468,000
8 1/2% Senior Notes Due 2011 $36,000,000
The securities, which were trading at a discount to par value, were
repurchased in exchange for approximately $69.6 million in cash.
In 2004, all of our outstanding HIGH TIDES I and HIGH TIDES II were
redeemed. At March 31, 2005, $517.5 million of principal amount of HIGH TIDES
III remained outstanding, including $115.0 million held by Calpine. The HIGH
TIDES III are scheduled to be remarketed no later than August 1, 2005. In the
event of a failed remarketing, the relevant HIGH TIDES III will remain
outstanding as convertible securities at a term rate equal to the treasury rate
plus 6% per annum and with a term conversion price equal to 105% of the average
closing price of our common stock for the five consecutive trading days after
the applicable final failed remarketing termination date. While a failed
remarketing of our HIGH TIDES III would not have a material effect on our
liquidity position, it would impact our calculation of diluted earnings per
share ("EPS") and increase our interest expense. Even with a successful
remarketing, we would expect to have an increased dilutive impact on our EPS
based on a revised conversion ratio.
See Note 6 of the Notes to the Consolidated Condensed Financial Statements
for more information related to other financings and repurchases of various
issuances of debt in the first quarter of 2005.
Cash Flow Activities -- The following table summarizes our cash flow
activities for the periods indicated:
Three Months Ended
March 31,
2005 2004
---------- ----------
(In thousands)
Beginning cash and cash equivalents................... $ 783,428 $ 991,806
Net cash provided by (used in):
Operating activities................................ (114,592) (173,230)
Investing activities................................ (220,848) (71,371)
Financing activities................................ 368,710 (160,091)
Effect of exchange rates changes on
cash and cash equivalents......................... (4,086) (4,310)
--------- ---------
Net increase (decrease) in cash and
cash equivalents.................................. 29,184 (409,002)
--------- ----------
Ending cash and cash equivalents...................... $ 812,612 $ 582,804
========= ==========
Operating activities for the three months ended March 31, 2005, used net
cash of $114.6 million, as compared to $173.2 million for the same period in
2004. In the first quarter of 2005, there was an $82.8 million use of funds from
net changes in operating assets and liabilities, comprised of decreases in
accounts payable of $72.9 million, accrued payroll and related expenses of $23.1
million and $18.4 million in accrued property taxes, together with an increase
in net margin deposits posted to support CES contracting activity of $42.3
million. Offset against these, accounts receivable decreased by $61.1 million.
In the first quarter of 2004, we had a $137.7 million use of funds from net
changes in operating assets and liabilities, comprised of an increase of $61
million in net margin deposits, an increase of $23 million in accounts
receivable, a use of funds of $35 million related to higher payments and
pre-payments of property tax and $19 million in higher prepaid long-term service
agreement payments.
Investing activities for the three months ended March 31, 2005, consumed
net cash of $ 220.8 million, as compared to $71.4 million in the same period of
2004. Capital expenditures, including capitalized interest, for the completion
of our power facilities decreased from $414.9 million in 2004 to $257.3 million
in 2005 as there were fewer projects under construction. Investing activities in
2005 also reflected a $42.9 million decrease in restricted cash. Investing
activities in 2004 included the receipt of $176.9 million from the disposal of
the Lost Pines Power Plant and certain oil and gas properties, together with a
decrease in restricted cash of $346.3 million, offset by the purchase of the Los
Brazos Power Plant, the remaining 50% interest in the Aries Power Plant, and the
remaining 20% interest in Calpine Cogeneration Company's fleet of plants.
Financing activities for the three months ended March 31, 2005, provided
$368.7 million, as compared to a $160.1 million use of funds for the same period
in 2004. We continued our refinancing program in the first quarter of 2005 by
raising $260.0 million from a preferred security offering by Calpine Jersey II,
$144.7 million from various project financings and $213.1 million from a prepaid
commodity derivative contract at our Deer Park facility. Also, we repaid $130.7
million of notes payable and project financing debt, in addition to using $61.2
million to repay Senior Notes and to repurchase Senior Notes due 2010 and 2011.
Additionally we incurred $47.9 million in financing and transaction costs.
Working Capital -- At March 31, 2005, we had a negative working capital
balance of approximately $299.1 million due primarily to (1) the classification
as current liabilities of the projected use of proceeds of $724.0 million for
bond purchase requirements (see Note 6 of the Notes to Consolidated Financial
Statements for a discussion), (2) an increase of $112.7 in net current
derivative liabilities from December 31, 2004, to March 31, 2005, and (3)
negative operating cash flow for the three months ended March 31, 2005.
Counterparties and Customers -- Our customer and supplier base is
concentrated within the energy industry. Additionally, we have exposure to
trends within the energy industry, including declines in the creditworthiness of
our marketing counterparties.
Currently, multiple companies within the energy industry are in bankruptcy
or have below investment grade credit ratings. However, we do not currently have
any significant exposures to counterparties that are not paying on a current
basis.
Letter of Credit Facilities -- At March 31, 2005 and December 31, 2004, we
had approximately $636.6 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, $231.2 million and $233.3 million, respectively,
were in aggregate issued under the cash collateralized letter of credit facility
and the corporate revolving credit facility at March 31, 2005 and December 31,
2004, respectively.
Commodity Margin Deposits and Other Credit Support -- As of March 31, 2005
and December 31, 2004, to support commodity transactions we had deposited net
amounts of $291.2 million and $248.9 million, respectively, in cash as margin
deposits with third parties, and we made gas and power prepayments of $82.7
million, and $78.0 million, respectively, and had letters of credit outstanding
of $109.0 million and $115.9 million, respectively. We use 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 this market.
Unrestricted Subsidiaries -- The information in this paragraph is required
to be provided under the terms of the indentures and credit agreement governing
the various tranches of our second-priority secured indebtedness (collectively,
the "Second Priority Secured Debt Instruments"). We have designated certain of
our subsidiaries as "unrestricted subsidiaries" under the Second Priority
Secured Debt Instruments. A subsidiary with "unrestricted" status thereunder
generally is not required to comply with the covenants contained therein that
are applicable to "restricted subsidiaries." The Company has designated Calpine
Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy Cogen, L.P. as
"unrestricted subsidiaries" for purposes of the Second Priority Secured Debt
Instruments. The following table sets forth selected balance sheet information
of Calpine Corporation and restricted subsidiaries and of such unrestricted
subsidiaries at March 31, 2005, and selected income statement information for
the three months ended March 31, 2005, (in thousands):
Calpine
Corporation
and Restricted Unrestricted
Subsidiaries Subsidiaries Eliminations Total
-------------- ------------- ------------- --------------
Assets................... $ 27,369,614 $ 435,964 $ (226,111) $ 27,579,467
============== ============= ============= ==============
Liabilities.............. $ 22,589,928 $ 251,185 $ -- $ 22,841,113
============== ============= ============== ==============
Total revenue............ $ 2,212,620 $ 1,639 $ (1,581) $ 2,212,678
Total cost of revenue.... (2,070,223) (3,621) 1,808 (2,072,036)
Interest income.......... 11,822 4,235 (1,726) 14,331
Interest expense......... (345,706) (3,231) -- (348,937)
Other.................... 24,918 315 -- 25,233
-------------- ------------- ------------- --------------
Net income............ $ (166,569) $ (663) $ (1,499) $ (168,731)
============== ============= ============= ==============
Bankruptcy-Remote Subsidiaries -- Pursuant to applicable transaction
agreements, we have established certain of our entities separate from Calpine
and our other subsidiaries. At March 31, 2005 these entities included: Rocky
Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside
Holdings, LLC, Calpine Energy Management, L.P., CES GP, LLC, Power Contract
Financing, LLC ("PCF"), Power Contract Financing III, LLC ("PCF III"), Calpine
Northbrook Energy Marketing, LLC, Calpine Northbrook Energy Marketing Holdings,
LLC ("CNEM"), 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 Deer Park LLC and Deer Park..
Indenture and Debt and Lease Covenant Compliance -- Our various indentures
place conditions on our ability to issue indebtedness, including further
limitations on the issuance of additional debt if our interest coverage ratio
(as defined in the various indentures) is below 2:1. Currently, our interest
coverage ratio (as so defined) is below 2:1 and, consequently, our indentures
generally would not allow us to issue new debt, except for (i) certain types of
new indebtedness that refinances or replaces existing indebtedness, and (ii)
non-recourse debt and preferred equity interests issued by our subsidiaries for
purposes of financing certain types of capital expenditures, including plant
development, construction and acquisition expenses. In addition, if and so long
as our interest coverage ratio is below 2:1, our indentures will limit our
ability to invest in unrestricted subsidiaries and non-subsidiary affiliates and
make certain other types of restricted payments. As of March 31, 2005, our
interest coverage ratio (as so defined) was below 1.75:1. Furthermore, until the
ratio is greater than 1.75:1, certain of the Company's indentures will prohibit
any further investments in non-subsidiary affiliates.
Certain of our indebtedness issued in the last half of 2004 was permitted
under our indentures on the basis that the proceeds would be used to repurchase
or redeem existing indebtedness. While we completed a portion of such
repurchases during the fourth quarter of 2004 and the first quarter of 2005, we
are still in the process of completing the required amount of repurchases. While
the amount of indebtedness that must still be repurchased will ultimately depend
on the market price of our outstanding indebtedness at the time the indebtedness
is repurchased, based on current market conditions, we estimate that, as of
March 31, 2005, as adjusted for market conditions and financial covenant
calculations, we would be required to spend approximately $294.0 million in
order to fully satisfy this requirement. This amount has been classified as
Senior Notes, current portion, on our Consolidated Condensed Balance Sheet.
Subsequent to March 31, 2005, we have satisfied a portion of such requirement.
See Note 14 of the Notes to Consolidated Condensed Financial Statements.
When we or one of our subsidiaries sells a significant asset or issues
preferred equity, our indentures generally require that the net proceeds of the
transaction be used to make capital expenditures or to repurchase or repay
certain types of subsidiary indebtedness, in each case within 365 days of the
closing date of the transaction. In light of this requirement, and taking into
account the amount of capital expenditures currently budgeted for 2005, we
anticipate that subsequent to March 31, 2005, we will need to use approximately
$250.0 of the net proceeds of the $360.0 million Two-Year Redeemable Preferred
Shares issued by our Calpine (Jersey) Limited ("Calpine Jersey I") subsidiary on
October 26, 2004, and approximately $180.0 million of the net proceeds of the
$260.0 million Redeemable Preferred Shares issued by our Calpine Jersey II on
January 31, 2005, to repurchase or repay certain subsidiary indebtedness.
Accordingly, $430.0 million of long-term debt has been reclassified as Senior
Notes, current portion, on our Consolidated Condensed Balance Sheet. The actual
amount of the net proceeds that will be required to be used to repurchase or
repay subsidiary debt will depend upon the actual amount of the net proceeds
that is used to make capital expenditures, which may be more or less than the
amount currently budgeted.
The total current debt obligation as of March 31, 2005, was $1,510.7
million, which consisted of $1,199.1 million of April through December 2005
repayments or maturities and $311.6 million of the $1,122.5 million 2006
repayments or maturities.
As noted above, we have significant debt maturities or bond purchase
requirements in 2005 as well as significant debt maturities in 2006 and beyond.
During the first quarter of 2005, our cash flow from operations used $114.6
million and at March 31, 2005, we had negative working capital of $299.1
million. In addition, as noted in Note 11 of the Notes to Consolidated Condensed
Financial Statements, certain bond holders have raised issues concerning the use
of proceeds from certain of the planned or recently executed transactions.
We have guaranteed the payment of a portion of the rents due under the
lease of the Greenleaf generating facilities in California. This lease is
between an owner trustee acting on behalf of Union Bank of California, as
lessor, and a Calpine subsidiary, Calpine Greenleaf, Inc., as lessee. We do not
currently meet the requirements of a financial covenant contained in the
guarantee agreement. The lessor has waived this non-compliance through May 15,
2005, and we are currently in discussions with the lessor to modify the lease,
Our guarantee thereof, and other related documents so as to eliminate the
covenant in question. In the event the lessor's waiver were to expire prior to
completion of this amendment, the lessor could at that time elect to accelerate
the payment of certain amounts owing under the lease, totaling approximately
$16.0 million. In the event the lessor were to elect to require us to make this
payment, the lessor's remedy under the guarantee and the lease would be limited
to taking steps to collect damages from us. The lessor would not be entitled to
terminate or exercise other remedies under the Greenleaf lease.
In connection with several of our subsidiaries' lease financing
transactions (Agnews, Geysers, Greenleaf, Pasadena, Rumford/Tiverton, 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.
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 the Company's 2004
Form 10-K, cash flow from operations is currently insufficient to meet in full
the Company's cash, liquidity and refinancing obligations for the year, so the
Company presently also depends in part upon its liquidity enhancing program and
refinancing program in order to fully service its debt. In addition, financing
agreements covering a substantial portion of the Company's subsidiaries and
other affiliates indebtedness, 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 March 31, 2005, our
effective tax rate on continuing operations decreased to 33% as compared to 41%
for the three months ended March 31, 2004. Our tax rate on continuing operations
for the quarter ended March 31, 2004, has been restated to reflect the
reclassification to discontinued operations of certain tax expense (benefit)
related to the sale of our oil and gas reserves (see Note 7 of the Notes to
Consolidated Condensed Financial Statements). Our effective tax rate on
continuing operations is based on the consideration of estimated full fiscal
year earnings and the effect of significant permanent differences in estimating
the quarterly effective rate, as well as establishing valuation allowances for
certain deferred tax assets.
Asset Sales -- As a result of the significant contraction in the
availability of capital for participants in the energy sector, we are
considering disposing of certain assets, which serves primarily to strengthen
our balance sheet through repayment of debt.
Accordingly, we are evaluating the potential sale of our Saltend Energy
Centre. We acquired the 1,200-MW power plant, located in Hull, England, in
August 2001 for approximately $800 million. Net proceeds from any sale of the
facility would be used to redeem the existing $360 million Two-Year Redeemable
Preferred Shares and then to redeem the $260 million Redeemable Preferred Shares
due July 30, 2005. Any remaining proceeds would be used in accordance with the
asset sale provisions of our existing bond indentures.
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 Special-Purpose Entities ("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.
In accordance with Accounting Principles Board ("APB") Opinion No. 18, "The
Equity Method of Accounting For Investments in Common Stock" and FASB
Interpretation No. 35, "Criteria for Applying the Equity Method of Accounting
for Investments in Common Stock (An Interpretation of APB Opinion No. 18)," the
third party debt on the books of our unconsolidated investments is not reflected
on our Consolidated Condensed Balance Sheet. At March 31, 2005, third party
investee debt was approximately $220.3 million. Of this amount, $59.6 million
relates to our investment in AELLC, for which the cost method of accounting was
used as of December 31, 2004. See following paragraph for a discussion of AELLC.
Based on our pro rata ownership share of each of the investments, our share
would be approximately $86.2 million. This amount includes the Company's share
for AELLC of $19.2 million. All such debt is non-recourse to us. The increase in
investee debt between periods is primarily due to borrowings for the Valladolid
III Energy Center currently under construction. See Note 5 of the Notes to
Consolidated Condensed Financial Statements for additional information on our
equity and cost method investments.
We own a 32.3% interest in AELLC. AELLC owns the 136-MW Androscoggin Energy
Center located in Maine and has construction debt of $59.6 million outstanding
as of March 31, 2005. The debt is non-recourse to Calpine Corporation (the
"AELLC Non-Recourse Financing"). On November 3, 2004, a jury verdict was
rendered against AELLC in a breach of contract dispute with IP. See Note 11 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. See Note 14 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 single B- from single 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. The ratings for the following debt issues remained unchanged:
the BBB- SPUR rating on Gilroy Energy Center bonds, the BB- rating on the Rocky
Mountain Energy Center and the Riverside Energy Center loans, the CCC+ rating on
the third lien CalGen debt and the BBB rating on the Power Contract Financing
LLC bonds. Such downgrade could increase the cost of future borrowings and other
costs of doing business.
On October 4, 2004, Fitch, Inc. assigned our first priority senior secured
debt a rating of BB-. At that time, Fitch also downgraded our second priority
senior secured debt from BB- to B+, downgraded our senior unsecured debt rating
from B- to CCC+, and reconfirmed our preferred stock rating at CCC. Fitch's
rating outlook for the Company is stable.
Moody's Investors Service currently has a senior implied rating on the
Company of B2 (with a stable outlook), and they rate our senior unsecured debt
at Caa1, and our preferred stock at Caa3.
Many other issuers in the power generation sector have also been downgraded
by one or more of the ratings agencies during this period. Such downgrades can
have a negative impact on our liquidity by reducing attractive financing
opportunities and increasing the amount of collateral required by trading
counterparties.
Capital Spending -- Development and Construction
Construction and development costs in process consisted of the following at
March 31, 2005 (in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP (1) CIP Costs Equipment
--------- ------------- ------------- ------------- -------------
Projects in active construction (2)............. 7 $ 2,246,703 $ 702,484 $ -- $ --
Projects in suspended construction.............. 3 1,137,452 396,248 -- --
Projects in advanced development................ 11 690,774 520,036 105,727 --
Projects in suspended development............... 6 419,105 168,985 37,728 --
Projects in early development................... 2 -- -- 8,952 --
Other capital projects.......................... NA 33,936 -- -- --
Unassigned equipment............................ NA -- -- -- 66,161
------------- ------------- ------------- -------------
Total construction and development costs...... $ 4,527,970 $ 1,787,753 $ 152,407 $ 66,161
============= ============= ============= =============
- ----------
<FN>
(1) Construction in Progress ("CIP")
(2) There are a total of eight projects in active construction. This includes
the seven projects that are recorded in CIP in the table above and one
project that is recorded in unconsolidated investments.
</FN>
Projects in Active Construction -- The seven projects in active
construction are projected to come on line from May 2005 to November 2007. These
projects will bring on line approximately 2,878 MW of base load capacity (3,210
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 March 31, 2005, the total projected costs to complete these
projects is $843.7 million and the estimated funding requirements to complete
these projects, net of expected project financing proceeds, is approximately
$48.3 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 will bring on line
approximately 1,769 MW of base load capacity (2,035 MW with peaking capacity).
We expect to finance the remaining $340.8 million projected costs to complete
these projects.
Projects in Advanced Development -- There are eleven projects in advanced
development. These projects will bring on line approximately 5,072 MW of base
load capacity (6,150 MW with peaking capacity). Interest and other costs related
to the development activities necessary to bring these projects to their
intended use are being capitalized. However, the capitalization of interest has
been suspended on four projects for which development activities are
substantially complete but construction will not commence until a PPA and
financing are obtained. The estimated cost to complete the eleven projects in
advanced development is approximately $3.1 billion. Our current plan is to
project finance these costs as PPAs are arranged.
Suspended Development Projects -- Due to current electric market
conditions, we have ceased capitalization of additional development costs and
interest expense on six development projects on which work has been suspended.
Capitalization of costs may recommence as work on these projects resumes, if
certain milestones and criteria are met indicating that it is again highly
probable that the costs will be recovered through future operations. As is true
for all 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 the recoverable
value. These projects would bring on line approximately 2,956 MW of base load
capacity (3,409 MW with peaking capacity). The estimated cost to complete these
projects is approximately $1.8 billion.
Projects in Early Development -- Costs for projects that are in early
stages of development are capitalized only when it is highly probable that such
costs are ultimately recoverable and significant project milestones are
achieved. Until then, all costs, including interest costs, are expensed. The
projects in early development with capitalized costs relate to two projects and
include geothermal drilling costs and equipment purchases.
Other Capital Projects -- Other capital projects primarily consist of
enhancements to operating power plants, oil and gas and geothermal resource and
facilities development as well as software developed for internal use.
Unassigned Equipment -- As of March 31, 2005, we had made progress payments
on four turbines and other equipment with an aggregate carrying value of $66.2
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. We are holding this equipment for
potential use on future projects. It is possible that some of this unassigned
equipment may eventually be sold, potentially in combination with our
engineering and construction services.
Impairment Evaluation -- All construction and development projects and
unassigned turbines are reviewed for impairment whenever there is an indication
of potential reduction in fair value. Equipment assigned to such projects is not
evaluated for impairment separately, as it is integral to the assumed future
operations of the project to which it is assigned. If it is determined that it
is no longer probable that the projects will be completed and all capitalized
costs recovered through future operations, the carrying values of the projects
would be written down to the recoverable value in accordance with the provisions
of SFAS No. 144 "Accounting for Impairment or Disposal of Long-Lived Assets"
("SFAS No. 144"). We review our unassigned equipment for potential impairment
based on probability-weighted alternatives of utilizing it for future projects
versus selling it. Utilizing this methodology, we do not believe that the
equipment not committed to sale is impaired. However, during the quarter ended
March 31, 2004, we recorded to the "Equipment cancellation and impairment cost"
line of the Consolidated Condensed Statement of Operations $2.4 million in
losses in connection with equipment cancellations, and we may incur further
losses should we decide to cancel more equipment contracts or sell unassigned
equipment in the future. In the event we were unable to obtain PPAs or project
financing and suspension or abandonment were to result, we could suffer
substantial impairment losses on such projects.
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 hedging, balancing
and optimization ("HBO") transactions. The former sales are recorded as
electricity and steam revenue and the latter sales are recorded as sales of
purchased power for hedging and optimization. The volumes in MWh for each
are key indicators of our respective levels of generation and HBO activity
and the sum of the two, our total deliveries of power, is relevant because
there are occasions where we can either generate or purchase power to
fulfill contractual sales commitments. Prospectively beginning October 1,
2003, in accordance with EITF 03-11, "Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to SFAS No. 133 and Not `Held
for Trading Purposes' As Defined in EITF Issue No. 02-3: "Issues Involved
in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" ("EITF
Issue No. 03-11"), 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 British
Thermal Units ("Btu") of fuel consumed per KWh generated. We calculate the
average heat rate for our gas-fired power plants (excluding peakers) by
dividing (a) fuel consumed in Btu's by (b) KWh generated. The resultant
heat rate is a measure of fuel efficiency, so the lower the heat rate, the
better. We also calculate a "steam-adjusted" heat rate, in which we adjust
the fuel consumption in Btu's down by the equivalent heat content in steam
or other thermal energy exported to a third party, such as to steam hosts
for our cogeneration facilities. Our goal is to have the lowest average
heat rate in the industry.
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 and the spread on sales of purchased power for hedging, balancing,
and optimization activity, by (b) total generated MWh's 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 "equity" gas from Calpine Natural
Gas, which is eliminated in consolidation), and the spread on sales of
purchased gas for hedging, balancing, and optimization activity by (b) the
heat content in millions of Btu's of the fuel we consumed in our power
plants for the period.
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.
o Average plant operating expense per normalized MWh. To assess trends in
electric power plant operating expense ("POX") per MWh, we normalize the
results from period to period by assuming a constant 70% total company-wide
capacity factor (including both base load and peaker capacity) in deriving
normalized MWh's. 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
March 31,
--------------------------------
2005 2004
-------------- --------------
(In thousands)
Operating Performance Metrics:
Total deliveries of power:
MWh generated............................................................................... 22,360 21,050
HBO and trading MWh sold.................................................................... 11,414 11,835
------------- -------------
MWh delivered............................................................................... 33,774 32,885
============= =============
Average availability......................................................................... 90% 92%
Average baseload capacity factor:
Average total consolidated gross MW in operation............................................ 26,368 21,852
Less: Average MW of pure peakers............................................................ 2,965 2,951
------------- -------------
Average baseload MW in operation............................................................ 23,403 18,901
Hours in the period......................................................................... 2,160 2,184
Potential baseload generation............................................................... 50,550 41,280
Actual total generation..................................................................... 22,360 21,050
Less: Actual pure peakers' generation....................................................... 229 273
------------- -------------
Actual baseload generation.................................................................. 22,131 20,777
Average baseload capacity factor............................................................ 43.8% 50.3%
Average heat rate for gas-fired power plants (excluding peakers) (Btu's/KWh):
Not steam adjusted.......................................................................... 8,369 8,167
Steam adjusted.............................................................................. 7,091 7,115
Average all-in realized electric price:
Electricity and steam revenue............................................................... $ 1,403,549 $ 1,245,886
Spread on sales of purchased power for hedging and optimization............................. 67,343 5,089
------------- -------------
Adjusted electricity and steam revenue (in thousands)....................................... $ 1,470,892 $ 1,250,975
MWh generated (in thousands)................................................................ 22,360 21,050
Average all-in realized electric price per MWh.............................................. $ 65.78 $ 59.43
Average cost of natural gas:
Fuel expense (in thousands)................................................................. $ 921,349 $ 789,749
Fuel cost elimination....................................................................... 43,011 53,066
Spread on sales of purchased gas for hedging and optimization............................... (7,037) 7,750
------------- -------------
Adjusted fuel expense....................................................................... $ 957,323 $ 850,565
Million Btu's ("MMBtu") of fuel consumed by generating plants (in thousands)................ 151,348 150,255
Average cost of natural gas per MMBtu....................................................... $ 6.33 $ 5.66
MWh generated (in thousands)................................................................ 22,360 21,050
Average cost of adjusted fuel expense per MWh............................................... $ 42.81 $ 40.41
Average spark spread:
Adjusted electricity and steam revenue (in thousands)....................................... $ 1,470,892 $ 1,250,975
Less: Adjusted fuel expense (in thousands).................................................. 957,323 850,565
------------- -------------
Spark spread (in thousands)................................................................. $ 513,569 $ 400,410
MWh generated (in thousands)................................................................ 22,360 21,050
Average spark spread per MWh................................................................ $ 22.97 $ 19.02
Add: Equity gas contribution (1)............................................................ $ 25,310 $ 34,295
Spark spread with equity gas benefits (in thousands)........................................ $ 538,879 $ 434,705
Average spark spread with equity gas benefits per MWh....................................... $ 24.10 $ 20.65
Average plant operating expense ("POX") per normalized MWh (for comparison
purposes we also include POX per actual MWh):
Average total consolidated gross MW in operations........................................... 26,368 21,852
Hours in the period......................................................................... 2,160 2,184
Total potential MWh......................................................................... 56,955 47,725
Normalized MWh (at 70% capacity factor)..................................................... 39,868 33,407
Plant operating expense (POX)............................................................... $ 195,626 $ 172,777
POX per normalized MWh...................................................................... $ 4.91 $ 5.17
Actual MWh generated (in thousands)......................................................... 22,360 21,050
------------- -------------
POX per actual MWh.......................................................................... $ 8.75 $ 8.21
------------- -------------
- ----------
<FN>
(1) Equity gas contribution margin:
</FN>
Three Months Ended
March 31,
--------------------------------
2005 2004
-------------- --------------
(In thousands)
Oil and gas sales.............................................................................. $ 10,820 $ 14,135
Add: Fuel cost eliminated in consolidation..................................................... 43,011 53,066
------------- -------------
Subtotal..................................................................................... $ 58,831 $ 67,201
Less: Oil and gas operating expense............................................................ 13,000 13,236
Less: Depletion, depreciation and amortization................................................. 15,521 19,670
------------- -------------
Equity gas contribution margin................................................................. $ 25,310 $ 34,295
MWh generated (in thousands)................................................................... 22,360 21,050
Equity gas contribution margin per MWh......................................................... $ 1.13 $ 1.63
The table below provides additional detail of total mark-to-market
activity. For the three months ended March 31, 2005 and 2004, mark-to-market
activities, net consisted of (dollars in thousands):
2005 2004
------------- -------------
Realized:
Power activity
"Trading Activity" as defined in EITF No. 02-03............................................. $ (2,125) $ 18,708
Other mark-to-market activity (1)........................................................... (6,813) (1,171)
------------- -------------
Total realized power activity......................................................... $ (8,938) $ 17,537
============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03............................................. $ (3,431) $ (74)
Other mark-to-market activity (1)........................................................... -- --
------------- -------------
Total realized gas activity........................................................... $ (3,431) $ (74)
============= =============
Total realized activity:
"Trading Activity" as defined in EITF No. 02-03............................................. $ (5,556) $ 18,634
Other mark-to-market activity (1)........................................................... (6,813) (1,171)
------------- -------------
Total realized activity............................................................... $ (12,369) $ 17,463
============= =============
Unrealized:
Power activity
"Trading Activity" as defined in EITF No. 02-03............................................. $ 24,041 $ (693)
Ineffectiveness related to cash flow hedges................................................. (1,038) (540)
Other mark-to-market activity (1)........................................................... (893) (9,795)
------------- -------------
Total unrealized power activity....................................................... $ 22,110 $ (11,028)
============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03............................................. $ (14,468) $ 637
Ineffectiveness related to cash flow hedges................................................. 1,196 5,446
Other mark-to-market activity (1)........................................................... -- --
------------- -------------
Total unrealized gas activity............................................................... $ (13,272) $ 6,083
============= =============
Total unrealized activity:
"Trading Activity" as defined in EITF No. 02-03.............................................. $ 9,573 $ (56)
Ineffectiveness related to cash flow hedges.................................................. 158 4,906
Other mark-to-market activity (1)............................................................ (893) (9,795)
------------- -------------
Total unrealized activity................................................................... $ 8,838 $ (4,945)
============= =============
Total mark-to-market activity:
"Trading Activity" as defined in EITF No. 02-03.............................................. $ 4,017 $ 18,578
Ineffectiveness related to cash flow hedges.................................................. 158 4,906
Other mark-to-market activity (1)............................................................ (7,706) (10,966)
------------- -------------
Total mark-to-market activity............................................................... $ (3,531) $ 12,518
============= =============
- ----------
<FN>
(1) Activity related to our assets but does not qualify for hedge accounting.
</FN>
Overview
Summary of Key Activities
Finance -- New Issuances
Date Amount Description
---------------------------- --------------- -----------------------------------------------------------------------------
1/28/05..................... $100.0 million Complete a non-recourse credit facility for Metcalf
1/31/05..................... $260.0 million Calpine Jersey II completes issuance of Redeemable Preferred Shares due
July 30, 2005
3/1/05...................... $503.0 million Close a non-recourse project finance facility that provides $466.5 million
to complete construction of Mankato and Freeport as well as a $36.5 million
collateral letter of credit facility
Finance -- Repurchases
Date Amount Description
---------------------------- --------------- -----------------------------------------------------------------------------
1/1/05 - 3/31/05............ $31.8 million Repurchase of $31.8 million principal amount outstanding of 8 1/2% Senior
Notes Due 2011 for $23.0 million in cash plus accrued interest
1/1/05 - 3/31/05............ $48.7 million Repurchase of $48.7 million principal amount outstanding of 8 5/8% Senior
Notes Due 2010 for $35.0 million in cash plus accrued interest
Finance -- Other
Date Description
---------------------------- ----------------------------------------------------------------------------------------------
3/31/05..................... Deer Park enters into agreements with MLCI to sell power and buy gas from April 1, 2005, to
December 31, 2010, for a cash payment of $195.8 million, net of transaction costs, plus
additional cash payments as additional transactions are executed
Other:
Date Description
---------------------------- ----------------------------------------------------------------------------------------------
2/22/05..................... Announce the selection of Inland Energy Center as site for North American launch of General
Electric's most advanced gas turbine technology, the "H System (TM)"
2/23/05..................... NewSouth Energy, a newly formed subsidiary, launches an energy venture to better focus on
wholesale power customers and energy markets in the South
3/28/05..................... Announce the receipt of a contract to provide 75 megawatts of Transmission Must Run Services
to Alberta Electric System Operator with contract terms of March 17, 2005 to June 30, 2006,
with options to extend until June 2008
California Power Market
The volatility in the California power market from mid-2000 through
mid-2001 has produced significant unanticipated results, and as described in the
following risk factors, the unresolved issues arising in that market, where 42
of our 103 power plants are located, could adversely affect our performance.
We may be required to make refund payments to the California Power Exchange
("CalPX") and California Independent System Operator ("CAISO") as a result of
the California Refund Proceeding. On August 2, 2000, the California Refund
Proceeding was initiated by a complaint made at FERC by SDG&E under Section 206
of the FPA alleging, among other things, that the markets operated by the CAISO
and the CalPX were dysfunctional. FERC established a refund effective period of
October 2, 2000, to June 19, 2001 (the "Refund Period"), for sales made into
those markets.
On December 12, 2002, an 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
issued an order (the "March 26 Order") adopting many of the findings set forth
in the December 12 Certification. 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 California Refund Proceeding. We believe,
based on the information that we have analyzed to date, that any refund
liability that may be attributable to us could total approximately $9.9 million
(plus interest, if applicable), after taking the appropriate set-offs for
outstanding receivables owed by the CalPX and CAISO to Calpine. We believe we
have appropriately reserved for the refund liability that by our current
analysis would potentially be owed under the refund calculation clarification in
the March 26 Order. The final determination of the refund liability and the
allocation of payment obligations among the numerous buyers and sellers in the
California markets is subject to further Commission proceedings. 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, we are unable to predict the
timing of the completion of these proceedings or the final refund liability.
Thus, the impact on our business is uncertain.
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 CPUC, the CDWR, and the EOB. Also, on
April 27, 2004, The Williams Companies, Inc. ("Williams") entered into a
settlement of the California Refund Proceeding and other proceedings with the
three California investor-owned utilities; previously, Williams had entered into
a settlement of the same matters with the California governmental entities. The
Williams settlement with the California governmental entities was similar to the
settlement that Calpine entered into with the California governmental entities
on April 22, 2002. Calpine's settlement resulted in a FERC order issued on March
26, 2004, which partially dismissed Calpine from the California Refund
Proceeding to the extent that any refunds are owed for power sold by Calpine to
CDWR or any other agency of the State of California. On June 30, 2004, a
settlement conference was convened at the FERC to explore settlements among
additional parties. 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.
We have been mentioned in a show cause order in connection with the FERC
investigation into western markets regarding the CalPX and CAISO tariffs and may
be found liable for payments thereunder. On February 13, 2002, FERC initiated an
investigation of potential manipulation of electric and natural gas prices in
the western United States. This investigation was initiated as a result of
allegations that Enron and others used their market position to distort electric
and natural gas markets in the West. The scope of the investigation is to
consider whether, as a result of any manipulation in the short-term markets for
electric energy or natural gas or other undue influence on the wholesale markets
by any party since January 1, 2000, the rates of the long-term contracts
subsequently entered into in the West are potentially unjust and unreasonable.
On August 13, 2002, the FERC staff issued the Initial Report on Company-Specific
Separate Proceedings and Generic Reevaluations; Published Natural Gas Price
Data; and Enron Trading Strategies (the "Initial Report"), summarizing its
initial findings in this investigation. There were no findings or allegations of
wrongdoing by Calpine set forth or described in the Initial Report. On March 26,
2003, the FERC staff issued a final report in this investigation (the "Final
Report"). In the Final Report, the FERC staff recommended that FERC issue a show
cause order to a number of companies, including Calpine, regarding certain power
scheduling practices that may have been in violation of the CAISO's or CalPX's
tariff. The Final Report also recommended that FERC modify the basis for
determining potential liability in the California Refund Proceeding discussed
above. Calpine believes that it did not violate these tariffs and that, to the
extent that such a finding could be made, any potential liability would not be
material.
Also, on June 25, 2003, FERC issued a number of orders associated with
these investigations, including the issuance of two show cause orders to certain
industry participants. FERC did not subject Calpine to either of the show cause
orders. FERC also issued an order directing the FERC Office of Markets and
Investigations to investigate further whether market participants who bid a
price in excess of $250 per MWh hour into markets operated by either the CAISO
or the CalPX during the period of May 1, 2000, to October 2, 2000, may have
violated CAISO and CalPX tariff prohibitions. No individual market participant
was identified. We believe that we did not violate the CAISO and CalPX tariff
prohibitions referred to by FERC in this order; however, we are unable to
predict at this time the final outcome of this proceeding or its impact on
Calpine.
The energy payments made to us during a certain period under our QF
contracts with PG&E may be retroactively adjusted downward as a result of a CPUC
proceeding. Our QF contracts with PG&E provide that the CPUC has the authority
to determine the appropriate utility "avoided cost" to be used to set energy
payments 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 CalPX market clearing price
instead of the SRAC price administratively determined by the CPUC. Having
elected such option, our QF facilities were paid based upon the CalPX zonal
day-ahead clearing price ("CalPX Price") for various periods commencing in the
summer of 2000 until January 19, 2001, when the CalPX ceased operating a
day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine
whether the CalPX Price was the appropriate price for the energy component upon
which to base payments to QFs which had elected the CalPX-based pricing option.
One CPUC Commissioner at one point issued a proposed decision to the effect that
the CalPX Price was the appropriate energy price to pay QFs who selected the
pricing option then offered by Section 390. No final decision, however, has been
issued to date. Therefore, it is possible that the CPUC could order a payment
adjustment based on a different energy price determination. On January 10, 2001,
PG&E filed an emergency motion (the "Emergency Motion") requesting that the CPUC
issue an order that would retroactively change the energy payments received by
QFs based on CalPX-based pricing for electric energy delivered during the period
commencing during June 2000 and ending on January 18, 2001. On April 29, 2004,
PG&E, the Utility Reform Network, a consumer advocacy group, and the Office of
Ratepayer Advocates, 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 2004 Motion"). The
April 2004 Motion requests that the CPUC set a briefing schedule in R.99-11-022
to determine what is the appropriate price that should be paid to the QFs that
had switched to the CalPX Price. The PG&E Parties allege that the appropriate
price should be determined using the methodology that has been developed thus
far in the California Refund Proceeding discussed above. Supplemental pleadings
have been filed on the April 2004 Motion, but neither the CPUC nor the assigned
administrative law judge has issued any rulings with respect to either the April
2004 Motion or the initial Emergency Motion. We believe that the CalPX Price was
the appropriate price for energy payments for our QFs during this period, but
there can be no assurance that this will be the outcome of the CPUC proceedings.
The availability payments made to us under our Geysers' Reliability Must
Run contracts have been challenged by certain buyers as having been not just and
reasonable. CAISO, California Electricity Oversight Board, Public Utilities
Commission of the State of California, PG&E, SDG&E, and Southern California
Edison Company (collectively referred to as the "Buyers Coalition") filed a
complaint on November 2, 2001 at FERC requesting the commencement of a FPA
Section 206 proceeding to challenge one component of a number of separate
settlements previously reached on the terms and conditions of "reliability must
run" contracts ("RMR Contracts") with certain generation owners, including
Geysers Power Company, LLC, which settlements were also previously approved by
FERC. RMR Contracts require the owner of the specific generation unit to provide
energy and ancillary services when called upon to do so by the ISO to meet local
transmission reliability needs or to manage transmission constraints. The Buyers
Coalition has asked FERC to find that the availability payments under these RMR
Contracts are not just and reasonable. Geysers Power Company, LLC filed an
answer to the complaint in November 2001. To date, FERC has not established a
Section 206 proceeding. The outcome of this litigation and the impact on our
business cannot be determined at the present time.
Financial Market Risks
As we are primarily focused on generation of electricity using gas-fired
turbines, our natural physical commodity position is "short" fuel (i.e., natural
gas consumer) and "long" power (i.e., electricity seller). To manage forward
exposure to price fluctuation in these and (to a lesser extent) other
commodities, we enter into derivative commodity instruments.
The change in fair value of outstanding commodity derivative instruments
from January 1, 2005 through March 31, 2005, is summarized in the table below
(in thousands):
Fair value of contracts outstanding at January 1, 2005.................. $ 18,560
Cash gains recognized or otherwise settled during the period (1)........ (7,949)
Non-cash losses recognized or otherwise settled during the period (2)... (233)
Changes in fair value attributable to new contracts (3)................. (223,946)
Changes in fair value attributable to price movements (4)............... (115,175)
-----------
Fair value of contracts outstanding at March 31, 2005 .............. $ (328,743)
===========
Realized cash flow from fair value hedges (5)........................... $ 37,589
===========
- ----------
<FN>
(1) Realized gains from cash flow hedges and mark-to-market activity are
reflected in the tables below:
Realized value of cash flow hedges (a).......................... $ 11.0
Net of:
Terminated and monetized derivatives.......................... (5.7)
Equity method hedges.......................................... 0.4
-----------
Cash gains realized from cash flow hedges..................... $ 16.3
-----------
Realized value of mark-to-market activity (b)................... $ (12.4)
Net of:
Non-cash realized mark-to-market activity..................... (4.0)
-----------
Cash losses realized on mark-to-market activity............... (8.4)
-----------
Cash gains recognized or otherwise settled during the period.. $ 7.9
===========
(a) Realized value as disclosed in Note 8 of the Notes to Consolidated
Condensed Financial Statements
(b) Realized value as reported in the Consolidated Condensed Statements of
Operations under mark-to-market activities
(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 $213.1 million
derivative liability associated with a transaction by our Deer Park
facility as discussed in Note 8 of the Notes to Consolidated Condensed
Financial Statements.
(4) Net commodity derivative assets reported in Note 8 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>
The fair value of outstanding derivative commodity instruments at March 31,
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.................................. $ 163,355 $ 28,937 $ -- $ -- $ 192,292
Prices provided by other external sources............... (258,974) (130,704) 10,364 (31,877) (411,191)
Prices based on models and other valuation methods...... -- (28,883) (57,097) (23,864) (109,844)
----------- ----------- ---------- ---------- -----------
Total fair value...................................... $ (95,619) $ (130,650) $ (46,733) $ (55,741) $ (328,743)
=========== =========== ========== ========== ===========
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 March 31, 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 March 31,
2005)
Investment grade........................................ $ (105,018) $ (128,985) $ (46,691) $ (55,741) $ (336,435)
Non-investment grade.................................... 12,685 103 (20) -- 12,768
No external ratings..................................... (3,286) (1,768) (22) -- (5,076)
----------- ----------- ---------- ---------- -----------
Total fair value...................................... $ (95,619) $ (130,650) $ (46,733) $ (55,741) $ (328,743)
=========== =========== ========== ========== ===========
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 March 31, 2005:
Electricity............................... $ (569,065) $ (788,280)
Natural gas............................... 240,322 160,140
----------- ------------
Total.................................... $ (328,743) $ (628,140)
Derivative commodity instruments included in the table are those included
in Note 8 of the Notes to Consolidated Condensed Financial Statements. The fair
value of derivative commodity instruments included in the table is based on
present value adjusted quoted market prices of comparable contracts. The fair
value of electricity derivative commodity instruments after a 10% adverse price
change includes the effect of increased power prices versus our derivative
forward commitments. Conversely, the fair value of the natural gas derivatives
after a 10% adverse price change reflects a general decline in gas prices versus
our derivative forward commitments. Derivative commodity instruments offset the
price risk exposure of our physical assets. None of the offsetting physical
positions are included in the table above.
Price changes were calculated by assuming an across-the-board ten percent
adverse price change regardless of term or historical relationship between the
contract price of an instrument and the underlying commodity price. In the event
of an actual ten percent change in prices, the fair value of our derivative
portfolio would typically change by more than ten percent for earlier forward
months and less than ten percent for later forward months because of the higher
volatilities in the near term and the effects of discounting expected future
cash flows.
The primary factors affecting the fair value of our derivatives at any
point in time are (1) the volume of open derivative positions (MMBtu and MWh),
and (2) changing commodity market prices, principally for electricity and
natural gas. The total volume of open gas derivative positions increased by 76%
from December 31, 2004, to March 31, 2005, and the total volume of open power
derivative positions increased by 125% 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" ("SFAS No. 133"), the change since the last balance sheet
date in the total value of the derivatives (both assets and liabilities) is
reflected either in OCI, net of tax, or in the statement of operations as an
item (gain or loss) of current earnings. As of March 31, 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 months ended March 31,
2005, have reflected this. See Notes 8 and 9 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 March 31, 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
- --------------- ---------------- ----------------- ------------------ ------------
2011........... $ 58,178 4.5% 3-month US $ LIBOR $ (270)
2011........... 291,897 4.5% 3-month US $ LIBOR (1,385)
2011........... 209,833 4.4% 3-month US $ LIBOR (290)
2011........... 41,822 4.4% 3-month US $ LIBOR (58)
2011........... 7,181 6.9% 3-month US $ LIBOR (3,075)
2011........... 19,302 4.9% 3-month US $ LIBOR (317)
2011........... 14,363 4.9% 3-month US $ LIBOR (205)
2011........... 7,181 4.9% 3-month US $ LIBOR (103)
2011........... 9,651 4.9% 3-month US $ LIBOR (159)
2011........... 9,651 4.8% 3-month US $ LIBOR (159)
2011........... 7,181 4.8% 3-month US $ LIBOR (103)
2011........... 9,651 4.8% 3-month US $ LIBOR (159)
2011........... 7,181 4.8% 3-month US $ LIBOR (103)
2012........... 105,840 6.5% 3-month US $ LIBOR (8,737)
2016........... 20,865 7.3% 3-month US $ LIBOR (3,035)
2016........... 13,910 7.3% 3-month US $ LIBOR (2,021)
2016........... 41,730 7.3% 3-month US $ LIBOR (6,063)
2016........... 27,820 7.3% 3-month US $ LIBOR (4,042)
2016........... 34,775 7.3% 3-month US $ LIBOR (5,053)
---------- -----------
Total........ $ 938,012 4.7% $ (35,337)
========== ===========
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% $ (7,624)
2011........... 100,000 6-month US $ LIBOR 8.5% (8,622)
2011........... 200,000 6-month US $ LIBOR 8.5% (6,077)
2011........... 100,000 6-month US $ LIBOR 8.5% (12,463)
---------- ---------
Total........ $ 500,000 8.5% $ (34,786)
========== =========
The fair value of outstanding interest rate swaps and the fair value that
would be expected after a one percent adverse interest rate change are shown in
the table below (in thousands):
Fair Value After a 1.0%
Net Fair Value as of (100 Basis Point) Adverse
March 31, 2005 Interest Rate Change
-------------------- -------------------------
$ (70,123) $ (91,560)
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 March 31, 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........................ $ (15,142)
GBP-$US......................... (11,333)
$Cdn-$US........................ (90,338)
Other........................... (4,066)
Significant changes in exchange rates will also impact our Cumulative
Translation Adjustment ("CTA") balance when translating the financial statements
of our foreign operations from their respective functional currencies into our
reporting currency, the U.S. dollar. An example of the impact that significant
exchange rate movements can have on our Balance Sheet position occurred in 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 March 31, 2005, Compared to Three Months Ended March 31,
2004:
The major components of our foreign currency transaction gains from
continuing operations of $5.2 million and $10.0 million, respectively, for the
three months ended March 31, 2005 and 2004, respectively, are as follows
(amounts in millions):
2005 2004
-------- ---------
Gain (Loss) from $Cdn-$US fluctuations:........ $ 11.0 $ (0.7)
Gain from GBP-Euro fluctuations:............... 4.4 11.3
Loss from GBP-$US fluctuations:................ (9.1) --
Loss from other currency fluctuations:......... (1.1) (0.6)
-------- --------
Total....................................... $ 5.2 $ 10.0
======== ========
The $Cdn-$US gain for the three months ended March 31, 2005, was due
primarily to a strengthening of the U.S. dollar against the Canadian dollar
during the first 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 strengthened during the first
quarter of 2005, significant remeasurement gains were triggered on these loans.
This gain was partially offset by remeasurement losses 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.
The $Cdn-$US loss for the three months ended March 31, 2004 was moderate
despite the fact that the U.S. dollar strengthened considerably against the
Canadian dollar during the first 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 at
March 31, 2004. As a result, remeasurement gains that otherwise would have been
recognized within our Consolidated Condensed Statements of Operations were
recorded within CTA in accordance with SFAS No. 52. The $0.7 million loss was
due to remeasurement losses recognized on the translation of the interest
receivable associated with our large intercompany loan that has been deemed a
permanent investment under SFAS No. 52.
During the three months ended March 31, 2005 and March 31, 2004,
respectively, the Euro weakened against the GBP, triggering re-measurement gains
associated with our Euro-denominated 8 3/8% Senior Notes Due 2008.
The GBP-$US loss for the three months ended March 31, 2005 relates to
re-measurement gains associated with our US$360 million Two-Year Redeemable
Preferred Shares issued in October 2004 by our indirect, wholly owned
subsidiary, Calpine (Jersey) Limited. The remeasurement losses recognized were
driven by a significant weakening of the GBP against the U.S. dollar during the
first quarter of 2005. There is no comparable amount for the three months ended
March 31, 2004 as no such exposure existed prior to the closing of this
offering.
Available-for-Sale Debt Securities -- Through March 31, 2005, we have
repurchased $115.0 million par value of HIGH TIDES III. At March 31, 2005, the
repurchased HIGH TIDES III are classified as available-for-sale and recorded at
fair market value in Other Assets. The following tables present the debt
security by expected maturity date and fair market value as of March 31, 2005
(dollars in thousands):
Weighted Average
Interest Rate 2005 2006 2007 2008 Thereafter Total
--------------- ---- ---- ---- ---- ---------- --------
HIGH TIDES III... 5.00% $ -- $ -- $ -- $ -- $115,000 $115,000
Fair Market Value
------------------------------------
March 31, 2005 December 31, 2004
-------------- -----------------
HIGH TIDES III............................ $ 112,700 $ 111,550
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 include funding for the construction costs of
CalGen power plants (of which only the Pastoria Energy Center was still in
active construction at March 31, 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.
The following table summarizes by maturity date our variable-rate debt
exposed to interest rate risk as of March 31, 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.................................. $ 5,309 $ 7,482 $ 8,132 $ 9,271
Saltend preferred interest.............................................. -- 360,000 -- --
Riverside Energy Center project financing............................... 1,843 3,685 3,685 3,685
Rocky Mountain Energy Center project financing.......................... 1,325 2,649 2,649 2,649
---------- ---------- ---------- ----------
Total of 3-month US $LIBOR rate debt................................... 8,477 373,816 14,466 15,605
1-month EURLIBOR weighted average interest rate basis (4)
Thomassen revolving line of credit...................................... 2,525 -- -- --
---------- ---------- ---------- ----------
Total of 1-month EURLIBOR rate debt.................................... 2,525 -- -- --
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................................ -- -- 846 777
Mankato Energy Center project financing................................. -- -- 705 727
---------- ---------- ---------- ----------
Total 1-month US $LIBOR interest rate.................................. -- -- 1,551 1,504
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)
First Priority Secured Institutional Term Loan Due 2009 (CCFC I)........ 1,604 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.................... 1,604 3,208 3,208 3,208
(2)(4)
Second Priority Senior Secured Term Loan B Notes Due 2007............... 5,625 7,500 725,625 --
---------- ---------- ------------ ----------
Total of variable rate debt as defined at (2) below.................... 5,625 7,500 725,625 --
(3)(4)
Second Priority Senior Secured Floating Rate Notes Due 2007............. 3,750 5,000 483,750 --
Blue Spruce Energy Center project financing............................. 1,875 3,750 3,750 3,750
---------- ---------- ---------- ----------
Total of variable rate debt as defined at (3) below.................... 5,625 8,750 487,500 3,750
(5)(4)
First Priority Secured Term Loans Due 2009 (CalGen)..................... -- -- 3,000 6,000
Second Priority Secured Floating Rate Notes Due 2010 (CalGen)........... -- -- -- 3,200
Second Priority Secured Term Loans Due 2010 (CalGen).................... -- -- -- 500
---------- ---------- ---------- ----------
Total of variable rate debt as defined at (5) below.................... -- -- 3,000 9,700
---------- ---------- ---------- ----------
(6)(4)
Island Cogen............................................................ 11,337 -- -- --
Contra Costa............................................................ 163 171 179 187
---------- ---------- ---------- ----------
Total of variable rate debt as defined at (6) below.................... 163 171 179 187
---------- ---------- ---------- ----------
Grand total variable-rate debt instruments (8)......................... $ 35,356 $ 393,445 $1,236,704 $ 36,304
========== ========== ========== ==========
Fair Value
2009 Thereafter December 31, 2004(7)
---------- ---------- --------------------
3-month US $LIBOR weighted average interest rate basis (4)
MEP Pleasant Hill Term Loan, Tranche A.......................................... $ 9,433 $ 85,479 $ 125,106
Saltend preferred interest...................................................... -- -- 360,000
Riverside Energy Center project financing....................................... 3,685 343,451 360,034
Rocky Mountain Energy Center project financing.................................. 2,649 243,849 255,770
---------- ---------- ------------
Total of 3-month US $LIBOR rate debt........................................... 15,767 672,779 1,100,910
1-month EURLIBOR weighted average interest rate basis (4)
Thomassen revolving line of credit.............................................. -- -- 2,525
---------- ---------- ------------
Total of 1-month EURLIBOR rate debt............................................ -- -- 2,525
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 rate debt........................................... 231,475 -- 235,000
1-month US $LIBOR interest rate basis (4)
Freeport Energy Center project financing........................................ 687 52,422 54,732
Mankato Energy Center project financing......................................... 625 45,935 47,992
---------- ---------- ------------
Total 1-month US $LIBOR interest rate.......................................... 1,312 98,357 102,724
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)
First Priority Secured Institutional Term Loan Due 2009 (CCFC I)................ 365,190 -- 376,418
Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I)............ -- 408,811 408,811
---------- ---------- ------------
Total of variable rate debt as defined at (1) below............................ 365,190 408,811 785,229
(2)(4)
Second Priority Senior Secured Term Loan B Notes Due 2007....................... -- -- 643,673
---------- ---------- ------------
Total of variable rate debt as defined at (2) below............................ -- -- 643,673
(3)(4)
Second Priority Senior Secured Floating Rate Notes Due 2007..................... -- -- 427,884
Blue Spruce Energy Center project financing..................................... 3,750 81,397 98,272
---------- ---------- ------------
Total of variable rate debt as defined at (3) below............................ 3,750 81,397 526,156
(5)(4)
First Priority Secured Term Loans Due 2009 (CalGen)............................... 591,000 -- 600,000
Second Priority Secured Floating Rate Notes Due 2010 (CalGen)................... 6,400 622,439 632,039
Second Priority Secured Term Loans Due 2010 (CalGen)............................ 1,000 97,256 98,756
---------- ---------- ------------
Total of variable rate debt as defined at (5) below............................ 598,400 719,695 1,330,795
---------- ---------- ------------
(6)(4)
Island Cogen...................................................................... -- -- 11,337
Contra Costa...................................................................... 196 1,380 2,276
---------- ---------- ------------
Total of variable rate debt as defined at (6) below............................ 196 1,380 2,276
---------- ---------- ------------
Grand total variable-rate debt instruments (8)................................. $1,216,090 $2,662,419 $ 5,420,625
========== ========== ============
- ----------
<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
March 31, 2005.
(8) The aggregate principal amount subject to variable interest rate risk is
$5,580,318 as of March 31, 2005.
</FN>
New Accounting Pronouncements
See Note 2 of the Notes to Consolidated Condensed Financial Statements for
a discussion of new accounting pronouncements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in Item 2.
Item 4. Controls and Procedures.
Disclosure Controls and Procedures.
Calpine Corporation (the "Company") maintains 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 Securities and Exchange Commission rules and forms, and that such
information is accumulated and communicated to the Company's management,
including its Chief Executive Officer and Chief Financial Officer, as
appropriate, to allow timely decisions regarding required disclosure.
As of December 31, 2004, management of the Company 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
quarter of 2005, the Company began taking the steps necessary to improve its
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 be able to complete the
required testing and to conclude that they are designed and operating
effectively.
The Company's senior management, including the Company's Chief Executive
Officer and Chief Financial Officer, evaluated the effectiveness of the
Company's disclosure controls and procedures as of the end of the period covered
by this quarterly report. Based on the status of the remediation of the material
weakness discussed below, the Company's Chief Executive Officer along with the
Company's Chief Financial Officer concluded that the Company's disclosure
controls and procedures are not effective. In light of the material weakness
identified as of December 31, 2004, and that continues to exist at March 31,
2005, the Company continued to perform additional analysis and post-closing
procedures to ensure its consolidated financial statements are prepared in
accordance with generally accepted accounting principles ("GAAP"). Accordingly,
management believes that the financial statements included in this report fairly
present in all material respects the Company's financial condition, results of
operations and cash flows for the periods presented. The certificates required
by this item are filed as Exhibits 31.1 and 31.2 to this Form 10-Q.
Status of Remediation of the Material Weakness
During the first quarter of 2005, the Company began taking the steps
necessary to improve its 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. The
Company has hired additional resources and has engaged third party tax experts
to improve the effectiveness of the controls over management's review of the
details of the income tax calculations. The Company has also improved the
process of preparing and reviewing the workpapers supporting its tax related
calculations and conclusions.
The Company will continue to do the following:
o Complete the implementation of the CorpTax computer application 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.
While certain elements of the program to remediate the tax material
weakness are still underway. The Company will continue to monitor the
effectiveness of these procedures and continue to make any changes that
management deems appropriate.
Changes in Internal Control Over Financial Reporting
The Company continuously seeks to improve the efficiency and effectiveness
of its internal controls. This results in refinements to processes throughout
the Company. During the first quarter of 2005, there were no significant changes
in the Company's internal control over financial reporting, other than the
changes related to the Company's tax accounting processes, procedures and
controls discussed above, that materially affected, or are reasonably likely to
materially affect, the Company's internal control over financial reporting.
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings.
See Note 11 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 Amended and Restated Certificate of Incorporation of the Company,
as amended through June 2, 2004.(a)
3.2 Amended and Restated By-laws of the Company.(b)
4.1.1 Amended and Restated Rights Agreement, dated as of September 19,
2001, between Calpine Corporation and Equiserve Trust Company,
N.A., as Rights Agent.(c)
4.1.2 Amendment No. 1 to Rights Agreement, dated as of September 28,
2004, between Calpine Corporation and Equiserve Trust Company,
N.A., as Rights Agent.(d)
4.1.3 Amendment No. 2 to Rights Agreement, dated as of March 18, 2005,
between Calpine Corporation and Equiserve Trust Company, N.A., as
Rights Agent.(e)
4.2 Memorandum and Articles of Association of Calpine European
Funding (Jersey) Limited.(f)
10.1 Credit Agreement, dated as of February 25, 2005, among Calpine
Steamboat Holdings, LLC, the Lenders named therein, Calyon New
York Branch, as a Lead Arranger, Underwriter, Co-Book Runner,
Administrative Agent, Collateral Agent and LC Issuer, CoBank,
ACB, as a Lead Arranger, Underwriter, Co-Syndication Agent and
Co-Book Runner, HSH Nordbank AG, as a Lead Arranger, Underwriter
and Co-documentation Agent, UFJ Bank Limited, as a Lead Arranger,
Underwriter and Co-Documentation Agent, and Bayerische Hypo-Und
Vereinsbank AG, New York Branch, as a Lead Arranger, Underwriter
and Co-Syndication Agent.(g)
10.2.1 Employment Agreement, dated as of January 1, 2005, between the
Company and Mr. Peter Cartwright.(h)(i)
10.2.2 Consulting Contract, dated as of January 1, 2005, between the
Company and Mr. George J. Stathakis.(g)(i)
10.2.3 Base Salary, Bonus, Stock Option Grant and Restricted Stock
Summary Sheet.(h)(i)
10.2.4 Form of Stock Option Agreement.(h)(i)
10.2.5 Form of Restricted Stock Agreement.(h)(i)
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 Annual Report on Form
10-K for the year ended December 31, 2001, filed with the SEC on March 29,
2002.
(c) Incorporated by reference to Calpine Corporation's Registration Statement
on Form 8-A/A (Registration No. 001-12079) filed with the SEC on September
28, 2001.
(d) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on September 30, 2004.
(e) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on March 23, 2005.
(f) 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.
(g) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2004, filed with the SEC on March 31,
2005.
(h) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on March 17, 2005.
(i) Management contract or compensatory plan or arrangement.
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: May 10, 2005
By: /s/ CHARLES B. CLARK, JR.
----------------------------------------------------------
Charles B. Clark, Jr.
Senior Vice President and Corporate
Controller (Principal Accounting Officer)
Date: May 10, 2005
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
Exhibit
Number Description
- ----------- -----------------------------------------------------------------
3.1 Amended and Restated Certificate of Incorporation of the Company,
as amended through June 2, 2004.(a)
3.2 Amended and Restated By-laws of the Company.(b)
4.1.1 Amended and Restated Rights Agreement, dated as of September 19,
2001, between Calpine Corporation and Equiserve Trust Company,
N.A., as Rights Agent.(c)
4.1.2 Amendment No. 1 to Rights Agreement, dated as of September 28,
2004, between Calpine Corporation and Equiserve Trust Company,
N.A., as Rights Agent.(d)
4.1.3 Amendment No. 2 to Rights Agreement, dated as of March 18, 2005,
between Calpine Corporation and Equiserve Trust Company, N.A., as
Rights Agent.(e)
4.2 Memorandum and Articles of Association of Calpine European
Funding (Jersey) Limited.(f)
10.1 Credit Agreement, dated as of February 25, 2005, among Calpine
Steamboat Holdings, LLC, the Lenders named therein, Calyon New
York Branch, as a Lead Arranger, Underwriter, Co-Book Runner,
Administrative Agent, Collateral Agent and LC Issuer, CoBank,
ACB, as a Lead Arranger, Underwriter, Co-Syndication Agent and
Co-Book Runner, HSH Nordbank AG, as a Lead Arranger, Underwriter
and Co-documentation Agent, UFJ Bank Limited, as a Lead Arranger,
Underwriter and Co-Documentation Agent, and Bayerische Hypo-Und
Vereinsbank AG, New York Branch, as a Lead Arranger, Underwriter
and Co-Syndication Agent.(g)
10.2.1 Employment Agreement, dated as of January 1, 2005, between the
Company and Mr. Peter Cartwright.(h)(i)
10.2.2 Consulting Contract, dated as of January 1, 2005, between the
Company and Mr. George J. Stathakis.(g)(i)
10.2.3 Base Salary, Bonus, Stock Option Grant and Restricted Stock
Summary Sheet.(h)(i)
10.2.4 Form of Stock Option Agreement.(h)(i)
10.2.5 Form of Restricted Stock Agreement.(h)(i)
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 Annual Report on Form
10-K for the year ended December 31, 2001, filed with the SEC on March 29,
2002.
(c) Incorporated by reference to Calpine Corporation's Registration Statement
on Form 8-A/A (Registration No. 001-12079) filed with the SEC on September
28, 2001.
(d) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on September 30, 2004.
(e) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on March 23, 2005.
(f) 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.
(g) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2004, filed with the SEC on March 31,
2005.
(h) Incorporated by reference to Calpine Corporation's Current Report on Form
8-K filed with the SEC on March 17, 2005.
(i) Management contract or compensatory plan or arrangement.